SEI-2013.12.31-10K
Table of Contents



 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 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, 2013
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 equity interests in the registrant are not held publicly. On February 18, 2014, there were a total of 100 shares of common stock, par value $0.001 per share, 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 7A.
 
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 STATEMENT 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 (the “Securities Act”), 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, among others. 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 “believe,” “expect,” “anticipate,” “estimate,” “project,” “propose,” “plan,” “target,” “foresee,” “should,” “intend,” “may,” “will,” “would,” “could,” “potential” 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 and their potential effect on us. 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,” “Item 7. 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 and readers are cautioned not to place undue reliance on such forward-looking statements. 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 herein, in this Annual Report and in our future periodic reports and registration statements 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 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 2014, we own approximately 40,000 square miles of onshore 3D data, consisting of 26,800 square miles in the United States (67%) and 13,200 square miles in Canada (33%). 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 50% of our onshore 3D library is comprised of data located in unconventional plays, and currently we have an additional 1,075 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, where we own a combined 8,200 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. We have grown our onshore 3D unconventional library by 12.9% 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 (55% - 75%) of the total cost of each survey (referred to as “client underwriting”). Seitel owns 100% of the acquired data and licenses (“resells”) the data 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 about three years on average and strong returns thereafter. Our long-lived, diverse data library built over three decades continues

3

Table of Contents



to provide value to our customers, with 46% of our 2013 3D onshore resale revenue coming from data over five years old, including resales of data from vintages as early as 1994.
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 (“E&P”) 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 Seitel Solutions business unit (“Solutions”), 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 2013, 2012 and 2011, approximately 98% of our revenues were 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 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
E&P companies consider seismic data an important tool in finding and exploiting hydrocarbons. E&P companies use seismic data in oil and gas exploration and development efforts to increase the probability of drilling success, to better delineate existing oil and gas fields and to augment their reservoir completion and management techniques. In unconventional plays, E&P companies 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. 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 library investment 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 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, 2013, 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 2009
 
$
45,995

 
46
%
 
$
490,148

 
67
%
Investments 2009 through 2013
 
54,414

 
54
%
 
236,223

 
33
%
Total 3D onshore
 
$
100,409

 
100
%
 
$
726,371

 
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, 2013 (in thousands): 
Total resale revenue – 3D onshore
$
100,409

Other revenue components:
 
Other resale revenue (principally 2D and offshore)
10,388

Acquisition revenue
87,312

Solutions and other revenue
4,765

Total revenue
$
202,874

The following presents a reconciliation of historical net investment for 3D onshore data (a non-GAAP financial measure) to net book value at December 31, 2013 (the most directly comparable GAAP financial measure) (in thousands):
 
Historical net investment in seismic data – 3D onshore
$
726,371

Add:
 
Acquisition revenue – 3D onshore
787,524

Other seismic data investment (principally 2D and offshore)
383,446

Foreign currency translation
36,079

Seismic projects in progress
63,744

Fair value adjustment resulting from the Merger
275,235

Less:
 
Historical impairment charges
(112,923
)
Accumulated amortization (including historical amounts pre-Merger)
(1,963,698
)
Net book value
$
195,778

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 $1.6 billion in gross investments and we view our library as an asset that would be time- and cost-prohibitive for others to replicate. Approximately 50% of our onshore 3D library is comprised of data located in unconventional plays, and we currently have 1,075 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 approximately 20,000 miles of data in unconventional areas. In addition, in 2013, we began acquiring data in the Permian Basin (West Texas Plays).
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 18, 2014:
  
 
Completed Surveys
 
Surveys in
Progress
3D Data Library
 
Square
Miles(1)
 
Percentage
of  Subtotal
 
Square
Miles
 
 
 
 
 
 
 
Eagle Ford/Woodbine
 
6,000

 
22
%
 
300

Niobrara/Bakken
 
2,600

 
10
%
 

Haynesville
 
1,350

 
5
%
 

Utica/Marcellus
 
1,100

 
4
%
 
250

Panhandle Plays
 
750

 
3
%
 

West Texas Plays
 

 
%
 
450

Conventional 3D
 
15,000

 
56
%
 

Total U.S. Onshore
 
26,800

 
100
%
 
1,000

 
 
 
 
 
 
 
Montney
 
3,800

 
29
%
 
25

Cardium
 
3,400

 
26
%
 
50

Horn River
 
1,050

 
8
%
 

Conventional 3D
 
4,950

 
37
%
 

Total Canada
 
13,200

 
100
%
 
75

 
 
 
 
 
 
 
Total 3D Onshore
 
40,000

 
79
%
 
1,075

 
 
 
 
 
 
 
U.S. Offshore
 
10,500

 
21
%
 

 
 
 
 
 
 
 
Worldwide Total
 
50,500

 
100
%
 
1,075

 
(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. 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.
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 seismic data in other areas, such as Alabama, California, Michigan and Northern Louisiana 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.

6

Table of Contents



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 executed 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 the survey is in progress or once it is completed is considered a resale license. All of our data acquisition activity during 2013 occurred in unconventional plays, primarily the Eagle Ford/Woodbine in Texas, Utica/Marcellus in Pennsylvania and West Virginia, Granite Wash (Panhandle Plays) in North Texas and Oklahoma, Permian (West Texas Plays) 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. and Canadian projects is processed by our internal data processing groups located in the United States and Canada. 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 certain 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 5D Interpolation, Pre-Stack Depth Migration volumes, Amplitude Versus Offset volumes, Complex Attribute volumes and Rock Property volumes. The cost of these products may be underwritten by one or more customers in exchange for a license or licenses to use the resulting data or we may determine to fund the cost of certain of these products based on anticipated demand by our clients. These data products are licensed to the industry on a non-exclusive basis. Work on these projects may be performed by our internal data 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.
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 $1.6 billion, $750 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 2014, we have approximately 20,000 square miles of unconventional 3D data, and our entire data acquisition backlog as of February 2014 is directed to oil and liquids-rich unconventional plays. We have grown our onshore 3D unconventional library by 12.9% compounded annually since the beginning of 2008. 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;

7

Table of Contents



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 key 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 $1.9 billion to build our data library. Over 85% 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 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 period on investments in unconventional plays has been short and we have proven our ability to license onshore data for extended periods after its creation. For the year ended December 31, 2013, 46% of total resale revenue for 3D onshore data came from data acquired before 2009, and we are still licensing data from 1994, our first onshore 3D onshore vintage year. For new data, we have a rapid payback period of about three years on average, with annual returns on investments averaging approximately 33% 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 economic 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

8

Table of Contents



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 because 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 2013, 2012 and 2011, we achieved 69%, 61% and 56% 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 key 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 2013 or 2012, while in 2011 we had one customer that accounted for approximately 11% of revenue.
We serve a market that includes over 1,600 companies in the oil and gas industry and our customers range from small E&P 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 more than 25 years of industry experience, while Marcia Kendrick, our CFO, joined us in 1993 and has over 20 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 55-75% of the cost of the survey, lowers our initial capital requirements and enhances our return on investment. We 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 2013, 2012 and 2011, we achieved 69%, 61% and 56% 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.
We own 100% of acquired data and license (or “resell”) the data 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 about three years on average, with strong returns thereafter. Our long-lived, diverse data library built over three decades continues to provide value to our customers, with 46% of our 2013 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.

9

Table of Contents



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 contributes to our cash resales. 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. In 2013, we began acquiring data in the Permian basin located in West Texas. 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. We have grown our onshore 3D unconventional library by 12.9%, compounded annually, since the beginning of 2008, an average increase of 1,721 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.
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: E&P companies consider seismic data an important tool in finding and exploiting hydrocarbons. E&P companies use seismic data in oil and gas exploration and development efforts to increase the probability of drilling success, to better delineate existing oil and gas fields and to augment their reservoir completion and management techniques. 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 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 that 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.

10

Table of Contents



Increased merger and acquisition 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 growth in North America is expected to remain in the mid to high single digits through at least 2017.
The majority of land drilling activity in North America in 2013 was focused on areas with oil and liquids-rich hydrocarbons, with oil directed rigs representing approximately 76% of the activity in 2013. The focus on oil and liquids-rich activity is expected to continue in 2014 in North America. Drilling activity in dry gas areas is expected to continue to be depressed until gas prices show sustained strength.
The Energy Information Administration (“EIA”) expects strong U.S. crude oil production growth continuing through 2015. Based on the EIA’s Short-Term Energy Outlook dated January 7, 2014, the EIA expects that the U.S crude oil supply will increase by 1.0 million barrels per day in 2014 and an additional 0.8 million barrels per day in 2015, with most of this production growth concentrated in the Bakken, Eagle Ford and Permian regions. The growth in domestic production has and will continue to contribute to a significant decline in petroleum imports as U.S. consumption is expected to remain relatively flat in 2014 and 2015. In its January 7, 2014 report, the EIA predicts the price of West Texas Intermediate crude oil to average $93 per barrel in 2014 and $90 per barrel in 2015, as compared to the average of $98 in 2013.
In this same report, the EIA projects that total U.S. natural gas consumption averaged a record high of 71.2 billion cubic feet per day (Bcf/d) in 2013, an increase of 1.5 Bcf/d, or 2.1%, from 2012. Projected U.S. natural gas consumption is expected to fall by 1.6 Bcf/d, or 2.2%, in 2014 then increase by 1.4 Bcf/d, or 2.0%, in 2015. The EIA expects U.S. production growth to continue in 2014 and 2015, largely driven by onshore production in unconventional areas. The EIA expects natural gas working inventories to remain at high levels. The EIA predicts that natural gas spot prices will gradually rise but remain relatively low through 2015, with an average of $3.89 per million British thermal units (MMBtu) in 2014 and $4.11 per MMBtu in 2015 as compared to the average of $3.73 per MMBtu in 2013.
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 E&P 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), Permian (West Texas Plays), Northern Montney and Cardium with several additional plays emerging, including Mowry and Point Pleasant in the United States 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 a key 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.

11

Table of Contents



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 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 our 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 E&P 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 18, 2014, we had capital expenditure commitments related to data creation projects of approximately $47.3 million, of which we have obtained approximately $32.7 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 February 19, 2013 of $103.0 million with underwriting of approximately $66.3 million.
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 E&P companies and private prospect generating individuals. During the years ended December 31, 2013 and 2012, 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.; Geophysical Pursuit, Inc.; Global Geophysical Services, Inc.; FairfieldNodal; Pulse Seismic Inc.; Seismic

12

Table of Contents



Exchange, Inc.; 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 requirements relating to environmental protection and worker health and safety laws. We invest financial and managerial resources to comply with these laws, regulations and related permit requirements. Various governmental authorities have the power to enforce compliance with these laws and regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including monetary 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 regulations as well as 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. For example, hydraulic fracturing has become the subject of increased public opposition and governmental regulation both in the United States and in foreign countries due to public concerns that the practice may adversely affect drinking water supplies and/or adversely affect local communities. In another example, a number of provincial, state, regional and foreign legal initiatives have emerged in recent years that seek to reduce greenhouse gas emissions and the U.S. Environmental Protection Agency (“EPA”), based on its findings that emissions of greenhouse gases present a danger to public health and the environment, has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, restrict emissions of greenhouse gases and require the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore production sources in the United States on an annual basis. The adoption of legislation, regulations or other regulatory initiatives imposing reporting obligations or placing restrictions on hydraulic fracturing activities or greenhouse gas emissives 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 "Item 1A. 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 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, 2013, we and our subsidiaries had 129 full-time employees, including seven executive officers, 19 marketing staff and 39 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,

13

Table of Contents



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
The risks described below could materially and adversely affect our business, financial condition and results of operations and the actual outcome of matters as to which forward-looking statements are made in this Form 10-K. The risk factors described below are not the only risks we face. Our business, financial condition and results of operations may also be affected by additional factors that are not currently known to us or that we currently consider immaterial or that are not specific to us, such as general economic conditions.
You should refer to the explanation of the qualifications and limitations on forward-looking statements included under “Cautionary Statement Regarding Forward-Looking Information” of this Form 10-K. All forward-looking statements made by us are qualified by the risk factors described below.

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 business 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:

the level 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;
technological advances affecting energy exploration, production and consumption;
weather, including seasonal patterns that affect regional energy demand as well as severe weather events that can disrupt supply;
the level of prices, and expectation about future prices, for oil and natural gas;
the ability of E&P companies to raise equity capital and debt financing or otherwise generate funds for exploration, development and production operations;
the cost of exploring for, developing and producing oil and natural gas;
the level of oil and natural gas reserves;
the rate of discovery of new oil and gas reserves and the decline of existing oil and gas reserves;
the ability of the Organization of Petroleum Exporting Countries to set and maintain production levels and prices for oil; and
the enactment and implementation of government policies, including environmental regulations and tax policies, regarding the exploration for, production and development of oil and natural gas reserves and the use of fossil fuels and alternative energy sources.

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, impact our seismic data business. Additionally, increases in oil and gas prices may not increase demand for our products and services or otherwise have a positive effect on our results of operations or financial condition. 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, sustained downturn in the oil and gas or seismic data industries, or sustained

14

Table of Contents



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 E&P 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 community infrastructure, including, for example, through increased truck traffic, hydraulic fracturing has become subject to increased opposition by certain environmental groups, resulted in numerous private and governmental studies, and triggering increased governmental regulation. The process is typically regulated by state oil and gas commissions, but the EPA has asserted limited regulatory authority over hydraulic fracturing, and has indicated it might seek to further expand its regulation of hydraulic fracturing. Also, the Bureau of Land Management has proposed regulations applicable to hydraulic fracturing conducted on federal and Indian oil and gas leases. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. Regional or state agencies with control over the withdrawal of water used in hydraulic fracturing activities may impose stringent conditions on, or delay or prohibit, such water withdrawals. At the state level, a growing number of states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. In addition, local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions related to the hydraulic fracturing process are adopted in areas where our E&P customers operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could reduce demand for our seismic data and related services. Furthermore, several federal governmental agencies are conducting reviews and studies to assess adverse impacts that hydraulic fracturing may have on drinking water or groundwater sources or otherwise to evaluate environmental aspects of fracturing activities, including the White House Council on Environmental Quality, the EPA and the U.S. Department of Energy. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing, which events could delay or curtail production of oil and natural gas by E&P operators, some of which are our customers, and thus reduce demand for our seismic data and related services. Any such decrease in the demand for our seismic data and related services could have a material adverse effect on our revenues and results of operations.
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 fluctuate widely. Prolonged or substantial declines in crude oil and/or 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. Prolonged or substantial declines in 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 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.

15

Table of Contents



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.
The cyclical nature of the oil and gas industry can have a significant effect on our revenues and profitability. Historically, oil and natural gas prices, as well as the level of exploration and developmental activity, have fluctuated significantly. These fluctuations have in the past, and may in the future, adversely affect our business. We are unable to predict future oil and natural gas prices or the level of oil and gas industry activity. A prolonged low level of activity in the oil and gas industry will likely depress development activity, adversely affecting the demand for our products and services and our financial condition and results of operations.

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 confidentiality of our proprietary, confidential information, we could be materially adversely affected.
Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.
We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and

16

Table of Contents



include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability for asserted claims.

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 55% - 75%) of our seismic acquisition project costs, including third-party project costs, is 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 appealing seismic data that we want to obtain, we may decide to take ownership in this data to cover a portion 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.

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 liability 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 that 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, which 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 in the United States and Canada 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 cash resales 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.

A reduction in 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.

17

Table of Contents




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

We perform an annual assessment of the recoverability of goodwill. 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 Canadian operations and financial condition 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 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 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, HSSE & SD Senior Vice-President, President of Seitel Data, Ltd. and President of Seitel Canada Ltd. (formerly known as 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 demand for our products and services are subject to various laws and regulations administered by federal, provincial, state and local governmental authorities and agencies in the United States and Canada. We may incur significant costs to attain or maintain compliance with these legal requirements. These laws and regulations may impose numerous obligations that are applicable to our operations including:
the acquisition of permits before commencing regulated activities;
the limitation or prohibition of seismic activities in environmentally sensitive or protected areas such as wetlands or wilderness areas; and
the application of specific health and safety criteria addressing worker protection.
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 hydraulic fracturing activities, emissions of greenhouse gases and the use of renewable energy sources rather than fossil fuels could adversely impact the operations of our customers. Also, future changes in these and other laws and regulations or additional regulations that adversely impact E&P operators, some of whom are our customers, could result in decreased demand for our products and services. Moreover, complying with more stringent regulations could cause an increase in our operating expenses, which could adversely affect our business.

18

Table of Contents



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 our business.

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 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, to monitor 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 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 regarding 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. In light 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 our business.

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, 2013, we had approximately $252.7 million of total outstanding indebtedness, including $2.7 million of capital leases. In addition, we have $30.0 million available for borrowing under our revolving credit facility, which had not been drawn on at December 31, 2013. Our 2014 consolidated annual debt service requirements are expected to aggregate approximately $24.2 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 which, 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.

19

Table of Contents



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 would be subject to changes in interest rates.
The indenture governing our $250.0 million aggregate principal amount of 9½% senior notes due 2019 ("the 9½% 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 9½% 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;
sell certain kinds of assets;
enter into transactions with affiliates; and
effect mergers or consolidations.
The restrictions contained in the indenture governing our 9½% 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 9½% 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 that sufficient assets will remain to repay the 9½% 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; Oklahoma City, Oklahoma and 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.

20

Table of Contents



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
  
1,506
  
Marketing
 
Leased
Irving, Texas
 
610
 
Marketing
 
Leased
New Orleans, Louisiana
  
364
  
Marketing
 
Leased
Oklahoma City, Oklahoma
  
234
  
Marketing
 
Leased
Pittsburgh, Pennsylvania
 
175
 
Marketing
 
Leased
Calgary, Alberta, Canada
 
14,909
 
Administrative; Financial; Marketing; Operations
 
Leased
Calgary, Alberta, Canada
  
42,985
  
Warehouse
 
Leased

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 resolution 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, 2013, 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
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, 2013, there was one holder of record of our 100 shares of common stock, $0.001 par value per share.
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 9½% 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.

21

Table of Contents




Item 6. Selected Financial Data

The following table summarizes certain historical consolidated financial data of the Company 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,
 
2013
 
2012
 
2011
 
2010
 
2009
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenue
$
202,874

 
$
240,458

 
$
218,008

 
$
175,556

 
$
115,345

Expenses and costs:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
121,598

 
139,754

 
142,963

 
175,592

 
150,199

Cost of sales
475

 
464

 
100

 
97

 
290

Selling, general and administrative
25,971

 
29,088

 
31,649

 
31,831

 
25,090

 
148,044

 
169,306

 
174,712

 
207,520

 
175,579

Income (loss) from operations
54,830

 
71,152

 
43,296

 
(31,964
)
 
(60,234
)
Interest expense, net
(27,851
)
 
(29,011
)
 
(34,767
)
 
(40,536
)
 
(40,696
)
Foreign currency exchange gains (losses)
(2,222
)
 
681

 
(726
)
 
441

 
1,008

Loss on early extinguishment of debt
(1,504
)
 

 
(7,912
)
 

 

Gain on sale of marketable securities

 
230

 
2,467

 
4,188

 

Other income
488

 
780

 
250

 
446

 
151

Income (loss) before income taxes
23,741

 
43,832

 
2,608

 
(67,425
)
 
(99,771
)
Provision (benefit) for income taxes
(89,940
)
 
6,782

 
392

 
(4,008
)
 
(2,974
)
Net income (loss)
$
113,681

 
$
37,050

 
$
2,216

 
$
(63,417
)
 
$
(96,797
)
 
 
As of December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
31,353

 
$
61,891

 
$
74,894

 
$
89,971

 
$
26,270

Seismic data library, net
195,778

 
180,117

 
120,694

 
106,104

 
200,389

Total assets
595,513

 
550,744

 
500,330

 
491,009

 
522,019

Total debt
252,676

 
278,142

 
278,256

 
405,604

 
405,732

Stockholder’s equity (deficit)
254,956

 
150,358

 
109,840

 
(7,022
)
 
46,361

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 consolidated financial statements included elsewhere in this document.
Overview
General
Our products and services are used by E&P companies in oil and gas exploration and development efforts to increase the probability of drilling success, to better delineate existing oil and gas fields and to augment their reservoir completion and management techniques. In unconventional plays, E&P companies 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 E&P 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

22

Table of Contents



existing data, E&P 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. Major integrated oil and gas companies and national oil companies have become more active in the North American market in recent years, 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 18, 2014, our clients' commitment for underwriting on new data creation projects was $32.7 million. Licensing data from our existing data library, or “off the shelf,” does not require the longer planning and lead times like new data creation and is thus more likely to fluctuate from 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 E&P companies and, in the case of new data creation, the willingness of these companies to forgo ownership in the seismic data. Capital expenditures by E&P 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, although there has been an overall decline in activity in the U.S. since 2010. 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.
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: Many companies shifted their capital expenditure focus to drilling in 2013; however, the rig count remained relatively flat due to operational efficiencies. This phenomenon is expected to continue in 2014. Drilling activity remains focused on areas with oil and liquids-rich hydrocarbons, while activity in dry gas areas continues to be depressed.

Availability of Capital for Our Customers: Some of our customers are independent E&P 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.
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.

23

Table of Contents



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,
 
2013
 
2012
 
2011
Cash resales
$
95,465

 
$
136,234

 
$
134,497

Other revenue components:
 
 
 
 
 
Acquisition underwriting revenue
87,312

 
107,254

 
77,406

Non-monetary exchanges
1,656

 
1,554

 
7,609

Revenue recognition adjustments
13,676

 
(10,257
)
 
(5,856
)
Solutions and other
4,765

 
5,673

 
4,352

Total revenue
$
202,874

 
$
240,458

 
$
218,008


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 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, net income (in thousands):
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
Cash EBITDA
$
75,064

 
$
115,347

 
$
112,031

Add (subtract) other revenue components not included in cash EBITDA:
 
 
 
 
 
Acquisition underwriting revenue
87,312

 
107,254

 
77,406

Non-monetary exchanges
1,656

 
1,554

 
7,609

Revenue recognition adjustments
13,676

 
(10,257
)
 
(5,856
)
Solutions non-cash revenue

 
20

 
71

Add (subtract) other items included in net income:
 
 
 
 
 
Depreciation and amortization
(121,598
)
 
(139,754
)
 
(142,963
)
Non-cash operating expenses
(869
)
 
(1,154
)
 
(743
)
Non-recurring corporate expenses
(411
)
 
(1,228
)
 
(1,792
)
Interest expense, net
(27,851
)
 
(29,011
)
 
(34,767
)
Foreign currency gains (losses)
(2,222
)
 
681

 
(726
)
Loss on early extinguishment of debt
(1,504
)
 

 
(7,912
)
Other income
488

 
380

 
250

Benefit (provision) for income taxes
89,940

 
(6,782
)
 
(392
)
Net income
$
113,681

 
$
37,050

 
$
2,216


24

Table of Contents



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, 2013, 2012 and 2011, we completed the addition of approximately 2,700 square miles, 2,800 square miles and 2,200 square miles, respectively, of seismic data to our library. As of February 18, 2014, we had 1,075 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 consolidated 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 consolidated 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. Contracts which are signed up to the time we make a firm commitment to create the new seismic survey are considered underwriting. Acquisition 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.    
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 agreement 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 licensed 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 consisting of 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 or data acquisition or as services are provided by Solutions, as applicable. These transactions are valued at the fair value of the data received or the fair value of the license granted or services provided, whichever is more readily determinable.

25

Table of Contents




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.
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 an annual assessment of the recoverability of goodwill as of October 1 of each year. We first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If the qualitative assessment indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount or we elect not to perform a qualitative assessment, the quantitative assessment or 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.

26

Table of Contents



Use of Estimates and Assumptions
In preparing our consolidated 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 consolidated 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, goodwill and realizability of our deferred tax assets.
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 77% as of January 1, 2014. 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 87% as of January 1, 2014.
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.

If it is necessary to perform an analysis to determine if our goodwill is impaired because either the qualitative assessment indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount or we elect not to perform a qualitative assessment, the two-step impairment test is performed 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.
In evaluating our ability to recover our U.S. deferred tax assets, we consider all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies and results of recent operations. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates management is using to manage the underlying business. If the projected future taxable income changes materially, we may be required to reassess the amount of valuation allowance recorded against our deferred tax assets.
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.

27

Table of Contents



Results of Operations
Revenue
The following table summarizes the components of our revenue for the years ended December 31, 2013, 2012 and 2011 (in thousands): 
 
Year Ended December 31,
 
2013
 
2012
 
2011
Acquisition underwriting revenue:
 
 
 
 
 
Cash underwriting
$
87,225

 
$
101,803

 
$
75,132

Underwriting from non-monetary exchanges
87

 
5,451

 
2,274

Total acquisition underwriting revenue
87,312

 
107,254

 
77,406

Resale licensing revenue:
 
 
 
 
 
Cash resales
95,465

 
136,234

 
134,497

Non-monetary exchanges
1,656

 
1,554

 
7,609

Revenue recognition adjustments
13,676

 
(10,257
)
 
(5,856
)
Total resale licensing revenue
110,797

 
127,531

 
136,250

Total seismic revenue
198,109

 
234,785

 
213,656

Solutions and other
4,765

 
5,673

 
4,352

Total revenue
$
202,874

 
$
240,458

 
$
218,008

Total revenue for the year ended December 31, 2013 was $202.9 million compared to $240.5 million for the year ended December 31, 2012. This decrease was due to a reduction in both acquisition underwriting revenue and resale licensing revenue. Acquisition underwriting revenue was $87.3 million in 2013, reflecting 69% underwriting on new data acquisition projects, compared to $107.3 million in 2012, reflecting 61% underwriting on new data acquisition projects. The decrease in acquisition underwriting revenue was primarily attributable to a reduction in data acquisition activity in Canada in 2013 due to a decline in capital spending by E&P companies in Canada. Our new data acquisition activity in 2013 continued to focus on areas with oil and liquids-rich hydrocarbons and primarily occurred in the Eagle Ford/Woodbine, Utica/Marcellus, Granite Wash (Panhandle Plays) and Permian (West Texas Plays) in the United States along with activity in the Cardium and Montney in Canada. Total resale licensing revenue was $110.8 million in 2013 compared to $127.5 million in 2012. Cash resales were $95.5 million in 2013 compared to $136.2 million in 2012. We believe that, overall in 2013, the North American land seismic market was soft. E&P companies were focused on cash flow generation, directing much of their capital spending towards production drilling. In addition, merger and acquisition activity in 2013 was less than in recent years. All of these factors contributed to our reduced level of cash resales in 2013. 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 2012 and 2013, which resulted in an increase in revenue recognized of $23.9 million between periods, was due to a decrease in the amount of new licensing contracts requiring deferral and an increase in selections of data from open library card contracts. These increases to revenue recognized were partially offset by a decrease in the recognition of revenue previously deferred. Solutions and other revenue was $4.8 million in 2013 compared to $5.7 million in 2012. The $0.9 million decrease was due to the variation in the types of products delivered and less revenue from third-party data processing projects in 2013.
Total revenue for the year ended December 31, 2012 was $240.5 million compared to $218.0 million for the year ended December 31, 2011. 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 was strong in 2012 driven by our strategic decision to grow our library, focusing on data in oil and liquids-rich areas of the key, active unconventional plays, both in the United States and Canada. In 2012, the majority of our new data acquisition activity was in the 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. 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

28

Table of Contents



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 an increase in revenue from third-party data processing projects.
At December 31, 2013, we had a deferred revenue balance of $41.7 million compared to the December 31, 2012 balance of $52.9 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 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):
 
2014.............................................................
$
38,152

2015............................................................
3,017

2016 and thereafter.....................................
570

Depreciation and Amortization
Depreciation and amortization was comprised of the following (in thousands):
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
Amortization of seismic data:
 
 
 
 
 
Income forecast
$
93,625

 
$
108,482

 
$
102,210

Straight-line
21,249

 
24,354

 
32,758

Total amortization of seismic data
114,874

 
132,836

 
134,968

Depreciation of property and equipment
1,020

 
1,127

 
2,167

Amortization of acquired intangibles
5,704

 
5,791

 
5,828

Total
$
121,598

 
$
139,754

 
$
142,963

Total seismic data library amortization amounted to $114.9 million, $132.8 million and $135.0 million in 2013, 2012 and 2011, 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 required in subsequent periods.

Seismic data amortization as a percentage of total seismic revenue is summarized as follows:
 
 
Year Ended December 31,
Components of Amortization
2013
 
2012
 
2011
Income forecast
47
%
 
46
%
 
48
%
Straight-line
11
%
 
10
%
 
15
%
Total
58
%
 
56
%
 
63
%
The percentage of income forecast amortization to total seismic revenue was 47% for the year ended December 31, 2013, 46% for the year ended December 31, 2012, and 48% for the year ended December 31, 2011. In all three years, we recognized resale revenue from data whose costs were fully amortized. In 2013, 58% of resales did not attract amortization, as compared to 63% in 2012 and 50% in 2011. Additionally, all acquisition revenue attracts amortization; thus, the decreasing level of acquisition revenue between 2012 and 2013 and the increasing level of acquisition revenue between 2011 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 amortization from 2011 to 2012 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. The timing and distribution of revenue among the various surveys was the reason for the decrease in straight-line amortization from 2012 to 2013.

29

Table of Contents



For each of the years ended December 31, 2013, 2012 and 2011, the rate 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, 2014, 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 $26.0 million in 2013, $29.1 million in 2012 and $31.6 million in 2011. SG&A expenses are made up of the following cash and non-cash expenses (in thousands):
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
Cash SG&A expenses
$
25,102

 
$
27,934

 
$
30,906

Non-cash compensation expense
869

 
761

 
453

Non-cash rent expense

 
393

 
290

Total
$
25,971

 
$
29,088

 
$
31,649

The decrease in cash SG&A expenses of $2.8 million from 2012 to 2013 was primarily due to (i) a decrease of $1.2 million in annual cash incentive compensation expense due to our cash EBITDA results falling below the target goals established for 2013, (ii) a $0.5 million decrease in commissions associated with our lower level of revenues in 2013, (iii) a decrease of $0.8 million in non-recurring expenses mainly related to debt restructure costs and (iv) $0.3 million in various other expenses.
The decrease in cash SG&A expenses of $3.0 million from 2011 to 2012 was primarily due to (i) 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 compared to 2011 when our Cash EBITDA was closer to the maximum established target, (ii) a $0.5 million decrease in our bad debt expense primarily due to collection of previously reserved receivables and (iii) 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.
Non-cash rent expense represented amortization of a favorable facility lease that was recorded as an intangible asset in connection with the Merger. This intangible asset became fully amortized in 2012.
Interest Expense
Interest expense was $28.2 million for the year ended December 31, 2013, $29.1 million for the year ended December 31, 2012 and $35.2 million for the year ended December 31, 2011. We refinanced our 9.75% senior notes due 2014 (“9.75% Senior Notes”) in March 2013, which resulted in a lower level of debt at a lower interest rate for the remainder of 2013. However, this decrease was partially offset by approximately $2.2 million of interest expense on our 9.75% Senior Notes that overlapped with interest incurred on the new senior notes (from the date of issuance of the new senior notes on March 20, 2013 until the legal discharge of the old senior notes on April 18, 2013). The decrease in interest expense in 2012 of $6.1 million was due to the repayment of $125.0 million of our 9.75% Senior Notes on July 1, 2011.
Loss on Early Extinguishment of Debt
In connection with the early extinguishment of our 9.75% Senior Notes in March 2013, we recorded a $1.5 million non-cash charge, which reflected the write-off of unamortized issue expenses. In 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.
Other Income (Expense)
During the years ended December 31, 2012 and 2011, we sold $0.2 million and $2.5 million, respectively, of marketable securities through multiple transactions on an active international exchange. Total gains were equal to the proceeds received.
During the years ended December 31, 2013, 2012 and 2011, we reported foreign currency transaction gains (losses) on U.S. denominated transactions of our Canadian subsidiaries totaling $(2.2) million, $0.7 million and $(0.7) million, respectively.

30

Table of Contents



Income Tax Expense (Benefit)
Income tax expense (benefit) was $(89.9) million, $6.8 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011, respectively, and is comprised of the following (in thousands):
 
Year Ended December 31,
 
2013
 
2012
 
2011
Release of U.S. federal and state valuation allowance on deferred tax assets
$
(100,492
)
 
$

 
$

U.S federal taxes, net of change in valuation allowance
9,088

 
342

 

U.S. state taxes, net of change in valuation allowance
1,084

 
1,065

 
(443
)
Canadian federal and provincial taxes
542

 
5,617

 
940

Canadian research and development tax credits
(361
)
 
(401
)
 
(366
)
Other
199

 
159

 
261

Total tax expense (benefit)
$
(89,940
)
 
$
6,782

 
$
392

At December 31, 2013, we released the full valuation allowance on our U.S. federal and state net deferred tax assets based on management’s assessment that it is more likely than not that our deferred tax assets will be realized. In making this assessment, we considered all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income and results of recent operations. The most significant piece of objective positive evidence available in assessing our U.S. deferred tax assets was our cumulative pretax income incurred over the three-year period ended December 31, 2013. Because our revenue activity does not occur evenly throughout the year and the fourth quarter is typically the quarter with the highest activity, we believed we needed a full year of results in 2013 in order to provide enough positive evidence to support our assessment related to the release of the valuation allowance. In addition, our projections of future taxable income show continued profitability. In projecting future taxable income, we began with recent historical results and incorporated assumptions about the amount of future pretax operating income and adjusted for items that do not have tax consequences. Our projections of future taxable income indicate we will have sufficient income to realize all of our existing deferred tax assets, the majority of which relate to net operating loss ("NOL") carryforwards. Adjustments to future estimates during the carry forward period could impact the analysis of NOL utilization. Our U.S. federal NOL carryforwards expire beginning 2025 through 2030 and our state NOL carryforwards expire beginning 2028 through 2031. Due to the significance of our NOL carryforwards, we also evaluated our ability to utilize our NOL carryforwards based on projected current taxable income, taking into consideration temporary differences, and determined that our NOL carryforwards would be utilized prior to their expiration. As a result, the valuation allowance was released.
Because we released the valuation allowance on our U.S. deferred tax assets in 2013, we are recording U.S. federal tax expense on our income beginning in 2013. In prior years, we had determined it was more likely than not that our deferred tax assets would not be realized; therefore, our U.S. federal tax expense was offset by a change in our valuation allowance resulting in no federal tax expense recorded in 2012 or 2011, other than that which resulted from our alternative minimum tax liability. U.S. state tax expense was consistent between 2013 and 2012. The U.S. state tax benefit recorded in 2011 resulted from refunds of prior taxes paid due to the filing of amended returns in certain states. The fluctuations in Canadian tax expense from 2011 to 2013 were primarily due to fluctuations in taxable income between the years. Other tax expense primarily relates to interest expense on uncertain tax positions.
Net Income
Net income was $113.7 million in 2013 compared to $37.1 million in 2012. The $76.6 million increase in net income from 2012 to 2013 was primarily due to a reduction of income tax expense of $96.7 million, the majority of which resulted from the reversal of the entire valuation allowance on our U.S. federal and state deferred tax assets. Net income in 2013 was also impacted by lower revenue partially offset by lower amortization of seismic data, lower SG&A expenses and lower interest expense as compared to 2012. In 2013, we also recorded a $1.5 million non-cash charge related to the early extinguishment of our 9.75% Senior Notes.
Net income was $37.1 million in 2012 compare to $2.2 million in 2011. The increase in net income of $34.8 million from 2011 to 2012 was due to higher revenue, lower amortization expense associated with our data library, a reduction in SG&A expenses, lower interest expense and a reduction in loss on early debt extinguishment. These positive variances were offset by higher income tax expense in 2012 compared to 2011.

31

Table of Contents



Liquidity and Capital Resources
As of December 31, 2013, we had $31.4 million in consolidated cash, cash equivalents and short-term investments, including $0.8 million of restricted cash. Our foreign subsidiary regularly holds cash that is used to reinvest in our Canadian operations. 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. Cash held by our foreign subsidiary fluctuates throughout the year and at December 31, 2013, was approximately $6.5 million.
In addition to the cash on our balance sheet, other sources of liquidity include our credit facility. For additional information regarding the Credit Facility and the 9½% Senior Notes, See “Note E - Debt” in the Notes to Consolidated Financial Statements herein.
Credit Facility: On May 25, 2011, we entered into a credit agreement (“Credit Facility”) that 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 based on our seismic data assets and eligible accounts receivable, each as defined in the Credit Facility, calculated on a monthly basis. U.S. borrowings under the Credit Facility accrue interest based on, at our option, either the London InterBank Offered Rate (“LIBOR”) plus an applicable margin, or the base rate, as defined in the agreement, plus an applicable margin. Canadian borrowings under the Credit Facility accrue interest based on a Canadian base rate, as defined in the agreement. In addition, we are required to pay an unused line fee of 0.50% per annum in respect of any unutilized commitments under the Credit Facility. The Credit Facility expires on May 25, 2016. As of December 31, 2013, no amounts were outstanding under the Credit Facility and there was $30.0 million of availability.
9½% Senior Unsecured Notes: On March 20, 2013, we issued in a private placement $250.0 million aggregate principal amount of our 9½% Senior Notes. The proceeds from the 9½% Senior Notes, together with $29.8 million cash on hand, were used to satisfy and discharge the 9.75% Senior Notes, including accrued interest of $4.8 million. Interest is payable in cash, semi-annually on April 15 and October 15 of each year.
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.
Contractual Obligations: The following table summarizes our future contractual obligations as of December 31, 2013 (in thousands):
 
 
 
 
 
Payments due by period
Contractual cash obligations
 
Total
 
2014
 
2015-2017
 
2018-2019
 
2020 and
thereafter
Debt obligations (1)(2)
 
$
380,625

 
$
23,750

 
$
71,250

 
$
285,625

 
$

Capital lease obligations (2)
 
3,462

 
420

 
1,200

 
851

 
991

Operating lease obligations
 
2,082

 
783

 
1,290

 
9

 

Total contractual cash obligations
 
$
386,169

 
$
24,953

 
$
73,740

 
$
286,485

 
$
991

 
(1)Debt obligations include the face amount of our 9½% Senior Notes totaling $250.0 million.
(2)Amounts include interest related to debt and capital lease obligations.
Cash Flows from Operating Activities: Cash flows provided by operating activities were $147.9 million, $171.5 million and $126.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. Operating cash flows for 2013 decreased from 2012 primarily due to (i) lower data acquisition activity resulting in reduced collections on acquisition underwriting partially offset by an increase in collections on cash resales, (ii) an increase in income taxes paid and (iii) higher interest payments in 2013 associated with the timing of payments under the 9½% Senior Notes and the satisfaction and discharge of our 9.75% Senior Notes. 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.

Cash Flows from Investing Activities: Cash flows used in investing activities were $145.7 million, $184.4 million and $127.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. Cash expenditures for seismic data were $144.6 million, $183.2 million and $127.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. The decrease in cash invested in seismic data for 2013 compared to 2012 was primarily due to decreased data acquisition activity in Canada partially offset by higher capital expenditure payments in the U.S. The increase in cash invested in seismic data for 2012 compared to 2011 was due to increased data acquisition activity in both the U.S. and Canada and due to strong activity in

32

Table of Contents



unconventional plays.
Cash Flows from Financing Activities: Cash flows used in financing activities were $32.3 million, $0.3 million and $14.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. The increase in cash flows used in financing activities in 2013 compared to 2012 was due to the refinancing of our 9.75% Senior Notes whereby we used $25.0 million cash on hand to pay down principal and paid $7.1 million in fees and expenses in connection with the issuance of our 9½% Senior Notes. 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 9½% 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 9½% 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). 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, 2013, we had a net deferred tax liability of $7.6 million attributable to our Canadian operations. In the United States, we had a federal deferred tax asset of $90.8 million and a state deferred tax asset of $1.7 million.
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 2013, capital expenditures for seismic data and other property and equipment amounted to $137.5 million on a gross basis and $46.2 million on a net cash basis. Our capital expenditures for 2014 are presently estimated to be $118.2 million on a gross basis and $35.0 million on a net cash basis. Our 2013 actual and 2014 estimated capital expenditures are comprised of the following (in thousands):
 
Year Ended December 31, 2013
 
Estimate for
Year Ending
December 31, 2014
New data acquisition
$
126,918

 
$
109,900

Cash purchases and data processing
4,743

 
1,900

Non-monetary exchanges
4,085

 
4,700

Property and equipment and other
1,737

 
1,700

Total capital expenditures
137,483

 
118,200

Less: Non-monetary exchanges
(4,085
)
 
(4,700
)
Changes in working capital
12,095

 

Cash investment per statement of cash flows
$
145,493

 
$
113,500


33

Table of Contents



Net cash capital expenditures represent total capital expenditures less cash underwriting revenue from our clients and non-cash additions to the seismic data library. We believe this measure is important as it reflects the amount of capital expenditures funded from our operating cash flow. The following table shows how our net cash capital expenditures (a non-GAAP financial measure) are derived from total capital expenditures, the most directly comparable GAAP financial measure (in thousands):
 
Year Ended December 31, 2013
 
Estimate for
Year Ending
December 31, 2014
Total capital expenditures
$
137,483

 
$
118,200

Less: Non-cash additions
(4,085
)
 
(4,700
)
Cash underwriting
(87,225
)
 
(78,500
)
Net cash capital expenditures
$
46,173

 
$
35,000

As of February 18, 2014, we had capital expenditure commitments related to data acquisition projects of approximately $47.3 million, of which we have obtained approximately $32.7 million of cash underwriting. See discussion of our sources of liquidity under “-Liquidity and Capital Resources.”
Recent Accounting Pronouncements
In July 2013, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") No. 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists." The ASU was issued to eliminate diversity in practice in the presentation of unrecognized tax benefits when a net operating loss ("NOL") carryforward, a similar tax loss or a tax credit carryforward exists. Under the new guidance, an entity should present an unrecognized tax benefit as a reduction of the deferred tax asset for an NOL or similar tax loss or tax credit carryforward rather than as a liability when the uncertain tax position would reduce the NOL or other carryforward under the tax law. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. The amendments in this ASU should be applied prospectively to all unrecognized tax benefits that exist at the effective date, but retrospective application is permitted. We are currently evaluating the impact of adopting the provisions of ASU 2013-11, but do not expect the standard to have a significant impact on our 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. Historically, we have not entered into financial instruments to mitigate these risks. We do not enter into derivative or other financial instruments for speculative or trading purposes.
Hypothetical changes in interest rates and foreign currency exchange rates chosen for the estimated sensitivity analysis are considered to be reasonable near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and foreign currency exchange rates, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.
The following information about our market-sensitive financial instruments constitutes a “forward-looking statement.”
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, 2013 and 2012, 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, 2013:
 
 
2014
 
2015
 
2016
 
2017
 
2018
 
There-after
 
Total
 
Fair Value
Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Rate
 
$

 
$

 
$

 
$

 
$

 
$
250,000

 
$
250,000

 
$
256,750

Average Interest Rate
 

 

 

 

 

 
9.50
%
 
9.50
%
 
 

34

Table of Contents



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
%
 
 

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.
Additionally, certain intercompany balances between our U.S. and Canadian subsidiaries are denominated in U.S. dollars. Since this is not the functional currency of our Canadian subsidiary, the changes in these balances are translated in our consolidated statements of income. As a result, we are exposed to foreign exchange risk as it relates to these intercompany balances. A sensitivity analysis indicates that, based on the intercompany balance as of December 31, 2013, if the U.S. dollar strengthened or weakened 3% (determined using an average of the last three years' historical exchange rates) against the Canadian dollar, the effect upon our consolidated statements of income would be approximately $1.0 million.

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 and are incorporated herein by reference.

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, 2013, 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. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that 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 is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 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, 2013 were designed to ensure, and were effective in ensuring, that our information required to be disclosed in the 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, 2013. In making this assessment, we used the criteria set forth in 1992 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, 2013, our internal control over financial reporting was effective.

35

Table of Contents



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 Section 404(c) of the Sarbanes-Oxley Act of 2002, as amended, that provides an exemption to issuers that are non-accelerated filers.
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, 2013 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
Not later than 120 days after December 31, 2013, we will amend this Annual Report on Form 10-K to include the information required by this item.

Item 11. Executive Compensation
Not later than 120 days after December 31, 2013, we will amend this Annual Report on Form 10-K to include the information required by this item.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Not later than 120 days after December 31, 2013, we will amend this Annual Report on Form 10-K to include the information required by this item.

Item 13. Certain Relationships and Related Transactions and Director Independence
Not later than 120 days after December 31, 2013, we will amend this Annual Report on Form 10-K to include the information required by this item.

Item 14. Principal Accountant Fees and Services
Not later than 120 days after December 31, 2013, we will amend this Annual Report on Form 10-K to include the information required by this item.
PART IV

Item 15. Exhibits, 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 Income
 
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:
The exhibits required to be filed by Item 601 of Regulation S-K are listed in the Exhibit Index immediately preceding the exhibits filed herewith and such listing is incorporated herein by reference.
 


36

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
 
 
(Duly Authorized Officer and Principal Executive Officer)
 
 
 
 
Date:
February 21, 2014
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 21, 2014
 
Gregory P. Spivy
 
 
 
 
 
 
 
 
 
 
/s/
Robert D. Monson
 
Chief Executive Officer, President and Director
 
February 21, 2014
 
Robert D. Monson
 
(Principal Executive Officer)
 
 
 
 
 
 
 
 
/s/
Marcia H. Kendrick
 
Chief Financial Officer
 
February 21, 2014
 
Marcia H. Kendrick
 
(Principal Financial Officer)
 
 
 
 
 
 
 
 
/s/
Allison A. Bennington
 
Director
 
February 21, 2014
 
Allison A. Bennington
 
 
 
 
 
 
 
 
 
 
/s/
Ryan M. Birtwell
 
Director
 
February 21, 2014
 
Ryan M. Birtwell
 
 
 
 
 
 
 
 
 
 
/s/
Dalton J. Boutte
 
Director
 
February 21, 2014
 
Dalton J. Boutte
 
 
 
 
 
 
 
 
 
 
/s/
Kevin P. Callaghan
 
Chief Operating Officer and Director
 
February 21, 2014
 
Kevin P. Callaghan
 
 
 
 
 
 
 
 
 
 
/s/
Kyle N. Cruz
 
Director
 
February 21, 2014
 
Kyle N. Cruz
 



 
 
 
 
 
 
 
 
/s/
Jay H. Golding
 
Director
 
February 21, 2014
 
Jay H. Golding
 
 
 
 
 
 
 
 
 
 
/s/
John E. Jackson
 
Director
 
February 21, 2014
 
John E. Jackson
 
 
 
 
 
 
 
 
 
 
/s/
Daniel R. Osnoss
 
Director
 
February 21, 2014
 
Daniel R. Osnoss
 
 
 
 

37

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, 2013. In making this assessment, management used the criteria set forth in 1992 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, 2013, 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 21, 2014


38

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, 2013 and 2012, and the related consolidated statements of income, comprehensive income (loss), stockholder's equity and cash flows for each of the years in the three-year period ended December 31, 2013. 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, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
/s/ BKD, LLP
Houston, Texas
February 21, 2014



39

Table of Contents




SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
 
December 31,
 
2013
 
2012
ASSETS
 
 
 
Cash and cash equivalents
$
31,353

 
$
61,891

Receivables
 
 
 
Trade, less allowance for doubtful accounts of $332 and $737, respectively
34,616

 
61,195

Notes and other, less allowance for doubtful accounts of $688 and $988, respectively
1,932

 
2,143

Due from Seitel Holdings, Inc. (Note K)
1,130

 
874

Income tax refund (Note D)
7,441

 

Seismic data library (Note B)
1,180,314

 
1,069,921

Less: Accumulated amortization
(984,536
)
 
(889,804
)
Net seismic data library
195,778

 
180,117

Property and equipment
19,043

 
18,279

Less: Accumulated depreciation and amortization
(14,432
)
 
(13,461
)
Net property and equipment
4,611

 
4,818

Prepaid expenses, deferred charges and other
9,844

 
10,774

Intangible assets, net (Note C)
14,762

 
20,828

Goodwill (Note C)
201,535

 
208,020

Deferred income taxes (Note D)
92,511

 
84

TOTAL ASSETS
$
595,513

 
$
550,744

LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
 
LIABILITIES
 
 
 
Accounts payable
$
23,189

 
$
37,521

Accrued liabilities
12,586

 
19,569

Employee compensation payable
2,002

 
5,693

Income taxes payable
787

 
4,134

Debt (Note E)
 
 
 
Senior Notes
250,000

 
275,000

Notes payable

 
29

Obligations under capital leases (Note F)
2,676

 
3,113

Deferred revenue (Note A)
41,739

 
52,857

Deferred income taxes (Note D)
7,578

 
2,470

TOTAL LIABILITIES
340,557

 
400,386

COMMITMENTS AND CONTINGENCIES (Note G)

 

STOCKHOLDER’S EQUITY
 
 
 
Common stock, par value $.001 per share; 100 shares authorized, issued and outstanding at December 31, 2013 and December 31, 2012

 

Additional paid-in capital
399,641

 
398,772

Retained deficit
(158,454
)
 
(272,135
)
Accumulated other comprehensive income
13,769

 
23,721

TOTAL STOCKHOLDER’S EQUITY
254,956

 
150,358

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
595,513

 
$
550,744


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

40

Table of Contents



SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands)
 
  
Year Ended December 31,
 
2013
 
2012
 
2011
REVENUE
$
202,874

 
$
240,458

 
$
218,008

EXPENSES:
 
 
 
 
 
Depreciation and amortization
121,598

 
139,754

 
142,963

Cost of sales
475

 
464

 
100

Selling, general and administrative
25,971

 
29,088

 
31,649

 
148,044

 
169,306

 
174,712

INCOME FROM OPERATIONS
54,830

 
71,152

 
43,296

Interest expense
(28,213
)
 
(29,143
)
 
(35,246
)
Interest income
362

 
132

 
479

Foreign currency exchange gains (losses)
(2,222
)
 
681

 
(726
)
Loss on early extinguishment of debt
(1,504
)
 

 
(7,912
)
Gain on sale of marketable securities

 
230

 
2,467

Other income
488

 
780

 
250

Income before income taxes
23,741

 
43,832

 
2,608

Provision (benefit) for income taxes
(89,940
)
 
6,782

 
392

NET INCOME
$
113,681

 
$
37,050

 
$
2,216

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



41

Table of Contents



SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
 
  
Year Ended December 31,
 
2013
 
2012
 
2011
Net income
$
113,681

 
$
37,050

 
$
2,216

Unrealized losses on securities held as available for sale, net of tax:
 
 
 
 
 
Unrealized net holding losses arising during the period

 
(32
)
 
(373
)
Less: Reclassification adjustment for realized gains included in earnings

 
(230
)
 
(2,467
)
Foreign currency translation adjustments
(9,952
)
 
2,969

 
(3,037
)
Comprehensive income (loss)
$
103,729

 
$
39,757

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


42

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, 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
)
 
21,014

Amortization of stock-based compensation costs

 

 
761

 

 

Net income

 

 

 
37,050

 

Foreign currency translation adjustments

 

 

 

 
2,969

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

 

 

 

 
(32
)
Reclassification adjustment for realized gains on securities held as available for sale included in earnings, net of tax

 

 

 

 
(230
)
Balance, December 31, 2012
100

 

 
398,772

 
(272,135
)
 
23,721

Amortization of stock-based compensation costs

 

 
869

 

 

Net income

 

 

 
113,681

 

Foreign currency translation adjustments

 

 

 

 
(9,952
)
Balance, December 31, 2013
100

 
$

 
$
399,641

 
$
(158,454
)
 
$
13,769

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


43

Table of Contents
SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


  
Year Ended December 31,
 
2013
 
2012
 
2011
Cash flows from operating activities:
 
 
 
 
 
Reconciliation of net income to net cash provided by operating activities:
 
 
 
 
 
Net income
$
113,681

 
$
37,050

 
$
2,216

Depreciation and amortization
121,598

 
139,754

 
142,963

Loss on early extinguishment of debt
1,504

 

 
7,912

Deferred income tax provision (benefit)
(86,863
)
 
1,222

 
(289
)
Foreign currency exchange losses (gains)
2,222

 
(681
)
 
726

Amortization of deferred financing costs
1,246

 
2,044

 
1,999

Amortization of debt premium

 

 
(56
)
Amortization of stock-based compensation
869

 
761

 
453

Amortization of favorable facility lease

 
393

 
290

Increase (decrease) in allowance for doubtful accounts
(300
)
 
(461
)
 
12

Non-cash other income
(377
)
 
(208
)
 
(98
)
Non-cash revenue
(2,486
)
 
(8,518
)
 
(9,514
)
Gain on sale of marketable securities

 
(230
)
 
(2,467
)
Decrease (increase) in receivables
26,915

 
(8,365
)
 
(20,277
)
Decrease (increase) in other assets
586

 
(43
)
 
(471
)
Increase (decrease) in deferred revenue
(10,093
)
 
6,520

 
11,108

Increase (decrease) in accounts payable and other liabilities
(20,572
)
 
2,243

 
(7,684
)
Net cash provided by operating activities
147,930

 
171,481

 
126,823

Cash flows from investing activities:
 
 
 
 
 
Cash invested in seismic data
(144,557
)
 
(183,244
)
 
(126,979
)
Cash paid to acquire property, equipment and other
(936
)
 
(1,422
)
 
(2,121
)
Net proceeds from sale of marketable securities