2014.12.31-10K (TO FILE)
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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, 2014
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  ý    No  ¨
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  ¨    No  ý
(Explanatory Note: The registrant is a voluntary filer and is therefore not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been required to file by Section 13 or 15(d) of the Securities Exchange Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934 during such timeframe.)
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 17, 2015, there were a total of 100 shares of common stock, par value $0.001 per share, outstanding.
 


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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.

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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 capital expenditure 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, liquids-rich and natural gas unconventional plays as well as conventional areas.
As of February 2015, we own over 41,000 square miles of onshore 3D data, consisting of 28,200 square miles in the United States (68%) and 13,400 square miles in Canada (32%). We have a leading market position in key geographies in the North American unconventional onshore oil and gas plays where exploration and production (“E&P”) companies have been focusing their efforts in recent years. Over 50% of our onshore 3D library is comprised of data located in unconventional plays, and currently we have an additional 1,400 square miles of onshore 3D data in progress in those areas. Since 2008, we have embarked upon a campaign to acquire data in key unconventional plays, adding over 10,000 square miles to our library.
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% to 75%) of the total cost of each survey (referred to as “client underwriting”). Seitel typically owns 100% of the acquired data and licenses the data to additional parties on a non-exclusive basis (referred to as “resales”). Such resales are unlimited in both time and amount and require minimal incremental cash costs, leading to a reasonably short payback period on recent investments of about three years on average and strong returns thereafter. Our long-lived, diverse data library built over three decades continues to provide value to our customers, with 38% of our 2014 3D onshore resale revenue coming from data over five years old, including resales of data from vintages as early as 1995.

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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 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 2014, 2013 and 2012, 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 L 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 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.

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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, 2014, 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 2010
 
$
48,516

 
38
%
 
$
507,251

 
67
%
Investments 2010 through 2014
 
80,449

 
62
%
 
247,202

 
33
%
Total 3D onshore
 
$
128,965

 
100
%
 
$
754,453

 
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 data to total revenue for the year ended December 31, 2014 (in thousands): 
Total resale revenue – 3D onshore
$
128,965

Other revenue components:
 
Other resale revenue (principally 2D and offshore)
5,112

Acquisition underwriting revenue
59,960

Solutions and other revenue
4,000

Total revenue
$
198,037

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, 2014 (the most directly comparable GAAP financial measure) (in thousands):
 
Historical net investment in seismic data – 3D onshore
$
754,453

Add:
 
Acquisition underwriting revenue – 3D onshore
854,742

Other seismic data investment (principally 2D and offshore)
384,193

Foreign currency translation
30,872

Seismic projects in progress
57,762

Fair value adjustment resulting from the Merger
275,235

Less:
 
Historical impairment charges
(112,923
)
Accumulated amortization (including historical amounts pre-Merger)
(2,079,255
)
Net book value
$
165,079

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 $1.8 billion in gross investments and we view our library as an asset that would be time- and cost-prohibitive for others to replicate. Over 50% of our onshore 3D library is comprised of data located in unconventional plays and we currently have 1,400 square miles of onshore 3D data in progress in those areas. We believe we are well positioned due to the geographic diversity of our data library, including data in oil-focused and liquids-rich plays such as the Eagle Ford/Woodbine, Permian Basin (West Texas Plays), Niobrara/Bakken, Utica/Marcellus, Granite Wash (Panhandle Plays), Montney and Cardium and in natural gas-focused plays such as the Haynesville and Horn River, with approximately 21,600 miles of data in unconventional areas.
Our library also consists of data targeted at conventional plays and shot before we embarked on our current strategy of targeting data from unconventional plays. We also own a library of 3D offshore data covering parts of the shelf and certain deep water areas in the Western and Central U.S. Gulf of Mexico. In addition, we own or manage approximately 1.1 million linear miles of 2D data concentrated primarily in North America, both onshore and offshore.

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The following table describes our 3D seismic data library as of February 17, 2015:
  
 
Completed Surveys
 
Surveys in
Progress
3D Data Library
 
Square
Miles (1)
 
Percentage
of  Subtotal
 
Square
Miles (1)
 
 
 
 
 
 
 
Eagle Ford/Woodbine
 
6,500

 
23
%
 
1,000

Niobrara/Bakken
 
2,600

 
9
%
 

Utica/Marcellus
 
1,400

 
5
%
 

Haynesville
 
1,350

 
5
%
 

Panhandle Plays
 
800

 
3
%
 

West Texas Plays
 
500

 
2
%
 
300

Conventional 3D
 
15,050

 
53
%
 
50

Total U.S. Onshore
 
28,200

 
100
%
 
1,350

 
 
 
 
 
 
 
Montney
 
3,900

 
29
%
 
50

Cardium
 
3,500

 
26
%
 
50

Horn River
 
1,050

 
8
%
 

Conventional 3D
 
4,950

 
37
%
 

Total Canada
 
13,400

 
100
%
 
100

 
 
 
 
 
 
 
Total 3D Onshore
 
41,600

 
80
%
 
1,450

 
 
 
 
 
 
 
U.S. Offshore
 
10,500

 
20
%
 

 
 
 
 
 
 
 
Worldwide Total
 
52,100

 
100
%
 
1,450

 
(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, we believe 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. We believe 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 changes in focus are made in accordance with the activity of our clients and our ability to shift with 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.

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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. Almost all of our data acquisition activity during 2014 occurred in unconventional plays, primarily the Eagle Ford/Woodbine in Texas, Permian in West Texas, Utica/Marcellus in Pennsylvania, 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 Houston and Calgary. 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 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, liquids-rich and natural gas unconventional plays as well as conventional areas. As of February 2015, we have approximately 21,600 square miles of unconventional 3D data, and almost our entire data acquisition backlog as of February 2015 is directed to oil and liquids-rich unconventional plays. We have grown our onshore 3D unconventional library by 12.1% compounded annually since the beginning of 2008. In the near term, we will focus on further development of existing plays where our clients are active. 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 clients' needs;
generate client trust by delivering surveys on time that meet oil and gas client requirements particularly those clients that are early participants; and
retain and grow valuable client relationships.

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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. Since 1994, we have invested approximately $2.0 billion to build our data library, with a gross investment of approximately $1.8 billion, $800 million net of underwriting, 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 with minimal incremental costs, if any. 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 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, 2014, 38% of total resale revenue for 3D onshore data came from data acquired before 2010 and included licensing data from 1995, one of our earliest vintage years. For recent investments, we have a reasonably short 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 Oil and Gas Industry Cycles: Our variable operating structure allows us to curtail overhead costs quickly during cyclical downturns in the oil and gas industry because we have no fixed overhead costs related to maintaining seismic equipment or crews and our employee compensation structure is commission-based and bonus-centric. 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. In addition, most of our capital expenditures are discretionary additions to our seismic data library with significant underwriting commitments from customers, allowing us to reduce capital expenditures when necessary.
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. We believe this, in addition to the majority of our capital expenditures being discretionary, minimizes our 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 70% and typically do not start work on new acquisition programs without an underwriting commitment. Additionally, we may seek higher levels of underwriting in order to minimize our cash investment while still adding new data to our library. For each of the years 2014 and 2013, we achieved 69% average underwriting levels, and for 2012, achieved 61% average underwriting 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. In addition, our revenue stream remains highly diversified. One customer accounted for approximately 13% of our revenue in 2014 while no single customer accounted for more than 10% of revenue in 2013 or 2012.
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.

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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% to 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 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 70% underwriting level for all new seismic acquisition projects on an aggregate basis. For each of the years 2014 and 2013, we achieved 69% average underwriting levels and for 2012, achieved 61% average underwriting 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 typically own 100% of the acquired data and license the data to additional parties on a non-exclusive basis. Such resales are unlimited in both time and amount and require no to minimal incremental cash costs, leading to a reasonably short payback period on recent 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 38% of our 2014 3D onshore resale revenue coming from data over five years old, including resales of data from vintages as early as 1995.
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.
Expand Library in a Disciplined and Cost-effective Manner: 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. 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. The decision to make capital investments is weighed against the estimated length of the payback period and projected return on capital. We believe ample opportunities exist to grow our library in existing plays and, as oil and gas industry activity dictates, to expand into emerging areas. 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 to 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.
Maintain a Strong Balance Sheet and Ample Liquidity: We believe a strong balance sheet and ample liquidity are critical elements to managing the business through industry cycles. We intend to fund data acquisitions with the cash flow generated from operations.

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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. 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.
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.
North American Oil and Gas Markets: The emergence of shale and other unconventional plays has led to significant increases in production of oil and natural gas in North America. This increased production has dramatically reduced the amount of oil the U.S. imports. For most of 2014, oil markets remained relatively balanced. However, in the fourth quarter of 2014 and continuing into early 2015, oil prices declined significantly due to several factors. Growing output from the U.S., coupled with OPEC’s commitment to maintain production quotas, has resulted in a higher market supply of oil at a time when oil demand is slowing. At the same time, production recovered in countries that had been experiencing political unrest. In addition, a strengthening U.S. dollar relative to other major currencies has contributed to lower demand for oil.

As a result of the recent decline in oil prices, E&P companies have announced reductions in their capital spending budgets for 2015. According to Barclay’s Global 2015 E&P Spending Outlook, spending is expected to decline as much as 30% or more if 2015 West Texas Intermediate crude oil prices stay in the $50s per barrel. In addition, natural gas prices remain relatively low, reflecting abundant supplies.
The Energy Information Administration (“EIA”) expects U.S. crude oil production to continue to grow in 2015 despite lower crude oil prices and reduced drilling. Based on the EIA’s Short-Term Energy Outlook dated February 10, 2015, the EIA expects U.S crude oil production to average 9.3 million barrels per day in 2015 and 9.5 million barrels per day in 2016 compared to 8.6 million barrels per day in 2014. Global consumption is expected to grow by 1.0 million barrels per day in both 2015 and 2016. In its February, 2015 report, the EIA predicts the price of West Texas Intermediate crude oil to average $55 per barrel in 2015 and $71 per barrel in 2016, as compared to the average of $93 in 2014.
In this same report, the EIA projects that total U.S. natural gas production will average 72.8 billion cubic feet per day (Bcf/d) in 2015 and 74.4 Bcf/d in 2016 compared to 70.2 Bcf/d in 2014. U.S. natural gas consumption is expected to grow slightly, averaging 74.3 Bcf/d in 2015 and 72.5 Bcf/d in 2016 compared to 73.3 Bcf/d in 2014. The EIA expects natural gas working inventories to remain at high levels. The EIA predicts that natural gas spot prices will remain relatively low through 2016, with an average of $3.05 per million British thermal units (MMBtu) in 2015 and $3.47 per MMBtu in 2016 as compared to the average of $4.39 per MMBtu in 2014.
As a result of the recent decline in oil prices and reduced capital spending by our clients announced for 2015, we anticipate that demand for our seismic data will decline. However, we are unable to predict the severity or duration of such decrease in demand. We believe we are well positioned to deal with this challenging environment due to our variable operating structure, asset-light business model and our strong cash balance at December 31, 2014.


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Importance of Seismic Data: 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.
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 17, 2015, we had capital expenditure commitments related to data creation projects of approximately $65.5 million, of which we have obtained approximately $45.0 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 18, 2014 of $47.3 million with underwriting of approximately $32.7 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. One customer accounted for approximately 13% of our revenue during the year ended December 31, 2014. During the years ended December 31, 2013 and 2012, no one customer accounted for more than 10% of revenue. 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

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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 Exchange, Inc.; TGS Nopec; Vector Seismic Data Processing, Inc.; 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 13.
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, 2014, we and our subsidiaries had 138 full-time employees, including eight executive officers, 20 marketing staff and 50 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.

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Available Information
We make available free of charge, or through the “Investor Relations” section of our website at www.seitel.com, access to our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is filed with, or furnished to, the SEC. Our Code of Business Conduct and Ethics is also available through the “Investor Relations-Corporate Governance” section of our website or in print to anyone who requests them.
The public may read and copy any materials filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549 and may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

Item 1A. Risk Factors
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 and the oil and gas industry is cyclical and our business could be adversely affected by the fluctuating level of capital expenditures by oil and gas companies and by the level and volatility of oil and natural gas prices and global supply and demand dynamics.
Our industry and the oil and gas industry generally are subject to cyclical fluctuations. Demand for our services depends upon spending levels by oil and gas companies for exploration, production, development and field management of oil and natural gas reserves and, in the case of new seismic data creation, the willingness of these companies to forgo ownership in the seismic data. Capital expenditures by oil and gas companies for these activities depend upon several factors, including actual and forecasted prices of oil and natural gas and those companies' short-term and strategic plans. Oil and natural gas prices in turn depend on local, regional and global events or conditions that affect supply and demand for the relevant commodity. These events or conditions are generally not predictable and include, among other things:
the level of supply and demand, the expectations regarding future supply and demand, and the actual levels of production of oil and natural gas;
the level of prices, and expectations regarding future prices, for oil and natural gas;
the ability or willingness of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain production levels for oil;
oil and gas production levels by non-OPEC countries;
worldwide political, military and economic conditions, including social and political unrest in Africa and the Middle East and domestic and foreign governmental regulations and actions (including export restrictions, sanctions, taxes, repatriations and nationalizations);
geopolitical uncertainty;
technological advances affecting energy exploration, production and consumption;
price, availability and government subsidies for alternative fuels;
weather, including seasonal patterns that affect regional energy demand as well as severe weather events that can disrupt supply;
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; and
the enactment and implementation of government policies, including environmental regulations and tax policies, regarding the exploration, production and development of oil and natural gas reserves and the use of fossil fuels and alternative energy sources.

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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 have resulted in and continue to 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 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 could 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

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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.
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 customers' 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 customers. In the event that a customer 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, and if we are unable to maintain its confidentiality, we could be materially negatively affected.

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 negatively affected.

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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. While we continue to implement various procedures and controls to monitor and mitigate security threats and to increase security for our information and infrastructure, this 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 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% to 75%) of our seismic acquisition project costs, including third-party project costs, is underwritten by our customers. We target an average of 60% to 70% 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. Any failure, however, by these third-party contractors to meet the requisite industry quality, safety and environmental standards may result in 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 may not be fully covered by insurance.

Competition for the acquisition of new seismic data is intense.

There are a number of geophysical services 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, but are not limited to (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) weather conditions, (5) 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 (6) technological or regulatory changes. These revenue fluctuations could produce unexpected adverse operating results in any period.


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

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

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

We perform an annual assessment of the recoverability of goodwill. 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 is 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. 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 our ability to attract and retain highly skilled geophysical professionals and other technical personnel. Failure to continue attracting and retaining 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, Chief Technology Officer, General Counsel, HSSE & SD Senior Vice-President, President of Seitel Data, Ltd. and President of Seitel Canada 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. Any inability to attract and retain key management personnel could have a material adverse effect on our ability to manage our business properly.
We are subject to certain types of claims in the ordinary course of business.
We may become involved in, named as a party to, or be the subject of, various legal matters, including regulatory proceedings, and litigation asserting claims for personal injury, property damage, trespass, and contract disputes. The outcome of pending or future proceedings cannot be predicted with certainty and may be determined adversely to us and, as a result, could have a material adverse effect on our assets, liabilities, business, financial condition, results of operations, cash flows and future prospects.

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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 and delays in order 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 First Nations and Native Americans 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. In the oil and gas industry more generally, protracted approval processes, including consultations with First Nations in Canada and Native Americans in the U.S., for proposed projects could dampen investment in new projects, and thereby negatively impact demand for our products and services.
Additionally, these laws, regulations and government policies may change as a result of political, economic or social climate. Such changes may alter the environment in which we do business as well as the demand for our products and services and, therefore, may impact the results of our operations or increase our liabilities. Stringent 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. Further future changes in these and other laws and regulations or the imposition of additional regulations that adversely impact E&P operators, some of which 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.
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.
Tax authorities may reassess our tax calculations, or may change their administrative policies to our detriment.
There can be no assurance that the relevant tax authorities will agree with how we calculate our income for tax purposes or that such tax authorities will not change their administrative practices to our detriment.


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RISKS RELATED TO OUR INDEBTEDNESS
Our level of indebtedness could adversely affect our financial condition and our ability to fulfill our payment obligations and operate our business.

As of December 31, 2014, we had approximately $252.2 million of total outstanding indebtedness, including $2.2 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, 2014. Our 2015 consolidated annual debt service requirements are expected to aggregate approximately $24.1 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.
In addition, our revolving credit facility bears interest at variable rates. If market interest rates increase, debt payments will rise, which would adversely affect our cash flow. Hedging strategies could be employed such that a portion of the aggregate principal amount of this credit facility carries a fixed rate of interest; however, 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.

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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.
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, 2014, 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, 2014, there was one holder of record of our 100 shares of common stock, $0.001 par value per share.

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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.

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,
 
2014
 
2013
 
2012
 
2011
 
2010
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenue
$
198,037

 
$
202,874

 
$
240,458

 
$
218,008

 
$
175,556

Expenses and costs:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
121,023

 
121,598

 
139,754

 
142,963

 
175,592

Cost of sales
304

 
475

 
464

 
100

 
97

Selling, general and administrative
29,799

 
25,971

 
29,088

 
31,649

 
31,831

 
151,126

 
148,044

 
169,306

 
174,712

 
207,520

Income (loss) from operations
46,911

 
54,830

 
71,152

 
43,296

 
(31,964
)
Interest expense, net
(25,029
)
 
(27,851
)
 
(29,011
)
 
(34,767
)
 
(40,536
)
Foreign currency exchange gains (losses)
(1,974
)
 
(2,222
)
 
681

 
(726
)
 
441

Loss on early extinguishment of debt

 
(1,504
)
 

 
(7,912
)
 

Gain on sale of marketable securities

 

 
230

 
2,467

 
4,188

Other income
63

 
488

 
780

 
250

 
446

Income (loss) before income taxes
19,971

 
23,741

 
43,832

 
2,608

 
(67,425
)
Provision (benefit) for income taxes
10,293

 
(89,940
)
 
6,782

 
392

 
(4,008
)
Net income (loss)
$
9,678

 
$
113,681

 
$
37,050

 
$
2,216

 
$
(63,417
)
 
 
As of December 31,
 
2014
 
2013
 
2012
 
2011
 
2010
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
59,175

 
$
31,353

 
$
61,891

 
$
74,894

 
$
89,971

Seismic data library, net
165,079

 
195,778

 
180,117

 
120,694

 
106,104

Total assets
579,756

 
595,513

 
550,744

 
500,330

 
491,009

Total debt
252,219

 
252,676

 
278,142

 
278,256

 
405,604

Stockholder’s equity (deficit)
253,089

 
254,956

 
150,358

 
109,840

 
(7,022
)
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

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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 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.
As a result of the recent decline in oil prices, E&P companies have announced reductions in their capital spending budgets for 2015. We anticipate that demand for our seismic data will decline as a result of reduced capital spending by our clients. However, we are unable to predict the severity or duration of such decrease in demand. We believe we are well positioned to deal with this challenging environment due to our variable operating structure, asset-light business model and our strong cash balance at December 31, 2014.
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.
Merger and Acquisition/Joint Venture Activity: Merger and acquisition activity continues to occur within our client base. This activity could have a negative impact on seismic companies that operate in markets with a limited number of participating clients. However, we believe that, over time, this activity could have a positive impact on our business as it should generate re-licensing fees, result in increased vitality in the trading of mineral interests and result in the creation of new independent customers through the rationalization of staff within those companies affected by this activity.
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: The decline in crude oil prices and the reduction in E&P spending expected in 2015 has already had a direct impact on drilling activity in North America. As of February 13, 2015, the North American land rig count had fallen by 276 rigs since January 2, 2015. Overall, in 2015, the rig count is expected to fall by more than 500 rigs.

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.

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Key Performance Measures
Management considers certain performance measures in evaluating and managing our financial condition and operating performance at various times and from time to time. Some of these performance measures are non-GAAP financial measures. Generally, a non-GAAP financial measure is a numerical measure of a company's performance, financial position or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with United States generally accepted accounting principles, or GAAP. These non-GAAP measures are not in accordance with, nor are they a substitute for, GAAP measures. These non-GAAP measures are intended to supplement our presentation of our financial results that are prepared in accordance with GAAP.
The following are the key performance measures considered by management.
Cash Resales
Cash resales represent new contracts for data licenses from our library, including data currently in progress, payable in cash. We believe this measure is important in assessing overall industry and client activity. Cash resales are likely to fluctuate quarter to quarter as they do not require the longer planning and lead times necessary for new data creation.
The following is a reconciliation of this non-GAAP financial measure to the most directly comparable GAAP financial measure, total revenue (in thousands): 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Cash resales
$
123,530

 
$
95,465

 
$
136,234

Other revenue components:
 
 
 
 
 
Acquisition underwriting revenue
59,960

 
87,312

 
107,254

Non-monetary exchanges
741

 
1,656

 
1,554

Revenue recognition adjustments
9,806

 
13,676

 
(10,257
)
Solutions and other
4,000

 
4,765

 
5,673

Total revenue
$
198,037

 
$
202,874

 
$
240,458


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-routine corporate expenses such as severance and legal, financial and other expenses related to corporate and strategic transactions).

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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,
 
2014
 
2013
 
2012
Cash EBITDA
$
98,943

 
$
75,064

 
$
115,347

Add (subtract) other revenue components not included in cash EBITDA:
 
 
 
 
 
Acquisition underwriting revenue
59,960

 
87,312

 
107,254

Non-monetary exchanges
741

 
1,656

 
1,554

Revenue recognition adjustments
9,806

 
13,676

 
(10,257
)
Solutions non-cash revenue

 

 
20

Add (subtract) other items included in net income:
 
 
 
 
 
Depreciation and amortization
(121,023
)
 
(121,598
)
 
(139,754
)
Non-cash operating expenses
(536
)
 
(869
)
 
(1,154
)
Non-routine and other corporate expenses
(980
)
 
(411
)
 
(1,228
)
Interest expense, net
(25,029
)
 
(27,851
)
 
(29,011
)
Foreign currency gains (losses)
(1,974
)
 
(2,222
)
 
681

Loss on early extinguishment of debt

 
(1,504
)
 

Other income
63

 
488

 
380

Benefit (provision) for income taxes
(10,293
)
 
89,940

 
(6,782
)
Net income
$
9,678

 
$
113,681

 
$
37,050

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 through non-monetary exchanges and (4) creating new value-added products from existing data within our library. For the years ended December 31, 2014, 2013 and 2012, we completed the addition of approximately 1,600 square miles, 2,700 square miles and 2,800 square miles, respectively, of seismic data to our library. As of February 17, 2015, we had 1,450 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;

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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.

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 completed and 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 Company applies a minimum amortization rate of 70%.
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

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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.
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.
We apply a minimum income forecast amortization rate of 70% and the effect of decreasing future sales by 20%, with all other factors remaining constant, would not cause the amortization rates to increase from 70% as of January 1, 2015.
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, 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.

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Actual results could differ materially from the estimates and assumptions that we use in the preparation of our financial statements. To the extent management's estimates and assumptions change in the future, the effect on our reported results could be significant to any particular reporting period.
Results of Operations
Revenue
The following table summarizes the components of our revenue for the years ended December 31, 2014, 2013 and 2012 (in thousands): 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Acquisition underwriting revenue:
 
 
 
 
 
Cash underwriting
$
59,922

 
$
87,225

 
$
101,803

Underwriting from non-monetary exchanges
38

 
87

 
5,451

Total acquisition underwriting revenue
59,960

 
87,312

 
107,254

Resale licensing revenue:
 
 
 
 
 
Cash resales
123,530

 
95,465

 
136,234

Non-monetary exchanges
741

 
1,656

 
1,554

Revenue recognition adjustments
9,806

 
13,676

 
(10,257
)
Total resale licensing revenue
134,077

 
110,797

 
127,531

Total seismic revenue
194,037

 
198,109

 
234,785

Solutions and other
4,000

 
4,765

 
5,673

Total revenue
$
198,037

 
$
202,874

 
$
240,458

Total revenue for the year ended December 31, 2014 was $198.0 million compared to $202.9 million for the year ended December 31, 2013. The decrease was mainly attributable to a $27.4 million reduction in acquisition underwriting revenue partially offset by a $23.3 million increase in resale licensing revenue. Acquisition underwriting revenue was $60.0 million in 2014, compared to $87.3 million in 2013, with each year reflecting 69% underwriting on new data acquisition projects. In 2014, we focused on reduced, but targeted, investment. This reduction directly impacts acquisition underwriting revenue. New data acquisition activity in 2014 was primarily focused in the Eagle Ford/Woodbine, Permian (West Texas Plays) and Utica/Marcellus in the United States and the Cardium and Montney areas in Canada. Total resale licensing revenue was $134.1 million in 2014 compared to $110.8 million in 2013. In 2014, cash resales totaled $123.5 million, an increase of $28.1 million, or 29%, compared to $95.5 million in 2013. We experienced stronger cash resale activity in 2014 in both unconventional and conventional areas, with a good distribution of activity among the various plays. Cash resales improved year over year in each quarter of 2014; however, we began to see some slowing of cash resale activity in the fourth quarter of 2014 due to the decline in crude oil prices. Non-monetary exchanges fluctuate year to year depending upon data available for trade and totaled $0.8 million in 2014 compared to $1.7 million 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 2013 and 2014, which resulted in a decrease in revenue recognized of $3.9 million between periods, was due to a decrease in selections on open library card contracts, partially offset by fewer deferrals on new data licensing contracts and an increase in revenue recognized on previously deferred direct licensing contracts. Solutions and other revenue was $4.0 million in 2014 compared to $4.8 million in 2013 and was lower primarily due to variation in the type and amount of products delivered.
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 primarily occurred in the Eagle Ford/Woodbine, Utica/Marcellus, Granite Wash (Panhandle Plays) and Permian along with activity in the Cardium and Montney. 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

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contributed to our reduced level of cash resales in 2013. 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.
At December 31, 2014, we had a deferred revenue balance of $34.5 million compared to the December 31, 2013 balance of $41.7 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):
 
2015.............................................................
$
29,748

2016............................................................
4,694

2017 and thereafter.....................................
75

Depreciation and Amortization
The table below sets forth the components of depreciation and amortization and presents seismic data amortization as a percentage of total seismic revenue for the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):
 
 
Year Ended December 31,
 
Percentage of Revenue
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Amortization of seismic data:
 
 
 
 
 
 
 
 
 
 
 
Income forecast
$
92,819

 
$
93,625

 
$
108,482

 
48
%
 
47
%
 
46
%
Straight-line
22,740

 
21,249

 
24,354

 
12
%
 
11
%
 
10
%
Total amortization of seismic data
115,559

 
114,874

 
132,836

 
60
%
 
58
%
 
56
%
Depreciation of property and equipment
975

 
1,020

 
1,127

 
 
 
 
 
 
Amortization of acquired intangibles
4,489

 
5,704

 
5,791

 
 
 
 
 
 
Total
$
121,023

 
$
121,598

 
$
139,754

 
 
 
 
 
 
Total seismic data library amortization amounted to $115.6 million, $114.9 million and $132.8 million in 2014, 2013 and 2012, 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.
The percentage of income forecast amortization to total seismic revenue was 48% for the year ended December 31, 2014, 47% for the year ended December 31, 2013, and 46% for the year ended December 31, 2012. In all three years, we recognized resale revenue from data whose costs were fully amortized. In 2014, 46% of resales did not attract amortization, as compared to 58% in 2013 and 63% in 2012. Additionally, all acquisition revenue attracts amortization; thus, the decreasing level of acquisition revenue between periods 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 is completed and becomes available for sale. The amount of straight-line amortization will vary between periods due to the distribution of revenue among the various surveys.
For each of the years ended December 31, 2014, 2013 and 2012, 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, 2015, the amortization rate to be utilized under the income forecast method is 70% for all components.

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Selling, General and Administrative Expenses
Selling, general and administrative (“SG&A”) expenses were $29.8 million in 2014, $26.0 million in 2013 and $29.1 million in 2012. SG&A expenses are made up of the following cash and non-cash expenses (in thousands):
 
Year Ended December 31,
 
2014
 
2013
 
2012
Cash SG&A expenses
$
29,263

 
$
25,102

 
$
27,934

Non-cash compensation expense
536

 
869

 
761

Non-cash rent expense

 

 
393

Total
$
29,799

 
$
25,971

 
$
29,088

Cash SG&A expenses increased $4.2 million in 2014 compared to 2013 primarily due to a $3.2 million increase in variable expenses. These variable expenses are comprised of commissions and annual incentive compensation and were higher in 2014 due to the increase in total resale licensing revenue and Cash EBITDA compared to 2013. Also contributing to the increase in cash SG&A from 2013 to 2014 were $0.6 million in legal, financial and other expenses associated with corporate strategic costs and $0.4 million in various other expenses.
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-routine expenses mainly related to debt restructure costs and (iv) $0.3 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 $25.2 million for the year ended December 31, 2014, $28.2 million for the year ended December 31, 2013 and $29.1 million for the year ended December 31, 2012. The decrease in interest expense in both 2014 and 2013 was due to our refinancing of 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 and 2014. In addition, interest expense in 2013 included 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).
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.
Other Income (Expense)
During the years ended December 31, 2014, 2013 and 2012, we reported foreign currency transaction gains (losses) on U.S. denominated transactions of our Canadian subsidiaries totaling $(2.0) million, $(2.2) million and $0.7 million, respectively.

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Income Tax Expense (Benefit)
Income tax expense (benefit) was $10.3 million, $(89.9) million and $6.8 million for the years ended December 31, 2014, 2013 and 2012, respectively, and is comprised of the following (in thousands):
 
Year Ended December 31,
 
2014
 
2013
 
2012
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
10,575

 
9,088

 
342

U.S. state taxes, net of change in valuation allowance
1,212

 
1,084

 
1,065

Canadian federal and provincial taxes
(1,680
)
 
542

 
5,617

Canadian research and development tax credits

 
(361
)
 
(401
)
Other
186

 
199

 
159

Total tax expense (benefit)
$
10,293

 
$
(89,940
)
 
$
6,782

Since releasing the valuation allowance on our U.S. deferred tax assets in 2013, we have been recording U.S. federal tax expense on our income in 2014 and 2013. In 2012, 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 other than that which resulted from our alternative minimum tax liability. U.S. state tax expense has remained fairly consistent from 2012 to 2014. The fluctuations in Canadian tax expense from 2012 to 2014 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 $9.7 million in 2014 compared to $113.7 million in 2013. The $104.0 million decrease primarily resulted because 2013 included a $100.5 million benefit related to the release of the entire valuation allowance on our U.S. federal and state deferred tax assets. Additional variances in net income were attributable to lower revenue and higher SG&A expenses, partially offset by lower interest expense. Also, 2013 included a $1.5 million charge related to the early extinguishment of our debt.
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 lower 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.
Liquidity and Capital Resources
As of December 31, 2014, we had $59.2 million in consolidated cash, cash equivalents and short-term investments, including $0.9 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, 2014, was approximately $10.6 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 (Canadian), 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

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December 31, 2014, no amounts were outstanding under the Credit Facility and there was $30.0 million of availability. To the best of our knowledge, we were in compliance with all covenants contained in the Credit Facility at December 31, 2014.
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. Interest is payable in cash, semi-annually on April 15 and October 15 of each year. The notes mature on April 15, 2019. To the best of our knowledge, we are in compliance with all covenants contained in the indenture governing our 9½% Senior Notes at December 31, 2014.
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, 2014 (in thousands):
 
 
 
 
Payments due by period
Contractual cash obligations
 
Total
 
2015
 
2016-2018
 
2019-2020
 
2021 and
thereafter
Debt obligations (1) (2)
 
$
356,875

 
$
23,750

 
$
71,250

 
$
261,875

 
$

Capital lease obligations (2)
 
2,791

 
371

 
1,121

 
780

 
519

Operating lease obligations
 
1,390

 
775

 
615

 

 

Total contractual cash obligations
 
$
361,056

 
$
24,896

 
$
72,986

 
$
262,655

 
$
519

 
(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 $124.3 million, $147.9 million and $171.5 million for the years ended December 31, 2014, 2013 and 2012, respectively. Operating cash flows for 2014 decreased from 2013 primarily due to a reduction in acquisition underwriting revenue resulting from lower data acquisition activity and lower collections on cash resales partially offset by income tax refunds received and reduced interest payments. 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.

Cash Flows from Investing Activities: Cash flows used in investing activities were $95.7 million, $145.7 million and $184.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. Cash expenditures for seismic data were $93.7 million, $144.6 million and $183.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. The decrease in cash invested in seismic data for 2014 compared to 2013 was primarily due to a planned reduction in data acquisition activity in the U.S. 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.
Cash Flows from Financing Activities: Cash flows used in financing activities were $0.2 million, $32.3 million and $0.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. The cash flows used in financing activities in 2013 were 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.
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 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.

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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, 2014, we had a net deferred tax liability of $5.3 million attributable to our Canadian operations. In the United States, we had a federal deferred tax asset of $80.6 million and a state deferred tax asset of $1.1 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 2014, capital expenditures for seismic data and other property and equipment amounted to $92.7 million on a gross basis and $31.8 million on a net cash basis. Our capital expenditures for 2015 are presently estimated to be $101.0 million on a gross basis and $28.0 million on a net cash basis. Our 2014 actual and 2015 estimated capital expenditures are comprised of the following (in thousands):
 
Year Ended December 31, 2014
 
Estimate for
Year Ending
December 31, 2015
New data acquisition
$
86,423

 
$
96,100

Cash purchases and data processing
4,174

 
2,800

Non-monetary exchanges
950

 
800

Property and equipment and other
1,160

 
1,300

Total capital expenditures
92,707

 
101,000

Less: Non-monetary exchanges
(950
)
 
(800
)
Changes in working capital
3,886

 

Cash investment per statement of cash flows
$
95,643

 
$
100,200

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, 2014
 
Estimate for
Year Ending
December 31, 2015
Total capital expenditures
$
92,707

 
$
101,000

Less: Non-cash additions
(950
)
 
(800
)
Cash underwriting
(59,922
)
 
(72,200
)
Net cash capital expenditures
$
31,835

 
$
28,000

As of February 17, 2015, we had capital expenditure commitments related to data acquisition projects of approximately $65.5 million, of which we have obtained approximately $44.8 million of cash underwriting and $0.2 million of underwriting from non-monetary exchanges. See discussion of our sources of liquidity under “Liquidity and Capital Resources.”
Recent Accounting Pronouncements
In August 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” This ASU provides guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. The amendments require management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. The new standard will be effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016.

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Early adoption is permitted. We are currently evaluating the impact of adopting ASU 2014-15, but do not expect that it will have a material effect on our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The objective of the ASU is to establish a single comprehensive model in accounting for revenue arising from contracts with customers and will supersede most of the existing revenue recognition guidance, including industry-specific guidance. The core principle of the guidance is that an entity recognizes revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also significantly expands disclosure requirements concerning revenues for most entities. We are required to adopt this ASU on January 1, 2017. Early application is not permitted, but once effective, entities have the option of using either a full retrospective or modified approach to adopt the new standard. We are currently evaluating the effect that ASU 2014-09 will have on our financial statements and financial statement disclosures.

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 long-term debt with fixed interest rates. As of December 31, 2014 and 2013, 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, 2014:
 
 
2015
 
2016
 
2017
 
2018
 
2019
 
There-after
 
Total
 
Fair Value
Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Rate
 
$

 
$

 
$

 
$

 
$
250,000

 
$

 
$
250,000

 
$
243,843

Average Interest Rate
 

 

 

 

 
9.50
%
 

 
9.50
%
 
 
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
%
 
 

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, 2014, if the U.S. dollar strengthened

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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 $0.5 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, 2014, 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, 2014 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, 2014. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (2013 Framework). Based on this assessment and such criteria, management believes that, as of December 31, 2014, our internal control over financial reporting was effective.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to 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, 2014 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, 2014, we will amend this Annual Report on Form 10-K to include the information required by this item.

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Item 11. Executive Compensation
Not later than 120 days after December 31, 2014, 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, 2014, 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, 2014, 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, 2014, 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.
 


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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 20, 2015
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 20, 2015
 
Gregory P. Spivy
 
 
 
 
 
 
 
 
 
 
/s/
Robert D. Monson
 
Chief Executive Officer, President and Director
 
February 20, 2015
 
Robert D. Monson
 
(Principal Executive Officer)
 
 
 
 
 
 
 
 
/s/
Marcia H. Kendrick
 
Chief Financial Officer
 
February 20, 2015
 
Marcia H. Kendrick
 
(Principal Financial Officer)
 
 
 
 
 
 
 
 
/s/
Allison A. Bennington
 
Director
 
February 20, 2015
 
Allison A. Bennington
 
 
 
 
 
 
 
 
 
 
/s/
Ryan M. Birtwell
 
Director
 
February 20, 2015
 
Ryan M. Birtwell
 
 
 
 
 
 
 
 
 
 
/s/
Dalton J. Boutte
 
Director
 
February 20, 2015
 
Dalton J. Boutte
 
 
 
 
 
 
 
 
 
 
/s/
Kevin P. Callaghan
 
Chief Operating Officer and Director
 
February 20, 2015
 
Kevin P. Callaghan
 
 
 
 
 
 
 
 
 
 
/s/
Kyle N. Cruz
 
Director
 
February 20, 2015
 
Kyle N. Cruz
 
 
 
 
 
 
 
 
 
 
/s/
Jay H. Golding
 
Director
 
February 20, 2015
 
Jay H. Golding
 
 
 
 
 
 
 
 
 
 
/s/
John E. Jackson
 
Director
 
February 20, 2015
 
John E. Jackson
 
 
 
 
 
 
 
 
 
 
/s/
Daniel R. Osnoss
 
Director
 
February 20, 2015
 
Daniel R. Osnoss
 
 
 
 

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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, 2014. In making this assessment, management used the criteria set forth in Internal Control—Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) . 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, 2014, 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 20, 2015


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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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ BKD, LLP
Houston, Texas
February 20, 2015



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SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
 
December 31,
 
2014
 
2013
ASSETS
 
 
 
Cash and cash equivalents
$
59,175

 
$
31,353

Receivables
 
 
 
Trade, less allowance for doubtful accounts of $268 and $332, respectively
53,250

 
34,616

Notes and other, less allowance for doubtful accounts of $0 and $688, respectively
1,698

 
1,932

Due from Seitel Holdings, Inc. (Note J)
1,143

 
1,130

Income tax refund

 
7,441

Seismic data library (Note B)
1,239,339

 
1,180,314

Less: Accumulated amortization
(1,074,260
)
 
(984,536
)
Net seismic data library
165,079

 
195,778

Property and equipment
18,828

 
19,043

Less: Accumulated depreciation and amortization
(14,971
)
 
(14,432
)
Net property and equipment
3,857

 
4,611

Prepaid expenses, deferred charges and other
10,075

 
9,844

Intangible assets, net (Note C)
10,013

 
14,762

Goodwill (Note C)
193,722

 
201,535

Deferred income taxes (Note D)
81,744

 
92,511

TOTAL ASSETS
$
579,756

 
$
595,513

LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
 
LIABILITIES
 
 
 
Accounts payable
$
18,433

 
$
23,189

Accrued liabilities
12,074

 
12,586

Employee compensation payable
3,893

 
2,002

Income taxes payable
197

 
787

Senior Notes (Note E)
250,000

 
250,000

Obligations under capital leases (Note F)
2,219

 
2,676

Deferred revenue (Note A)
34,517

 
41,739

Deferred income taxes (Note D)
5,334

 
7,578

TOTAL LIABILITIES
326,667

 
340,557

COMMITMENTS AND CONTINGENCIES (Note G)

 

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

 

Additional paid-in capital
400,177

 
399,641

Retained deficit
(148,776
)
 
(158,454
)
Accumulated other comprehensive income
1,688

 
13,769

TOTAL STOCKHOLDER’S EQUITY
253,089

 
254,956

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
579,756

 
$
595,513


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

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Table of Contents



SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands)
 
  
Year Ended December 31,
 
2014
 
2013
 
2012
REVENUE
$
198,037

 
$
202,874

 
$
240,458

EXPENSES:
 
 
 
 
 
Depreciation and amortization
121,023

 
121,598

 
139,754

Cost of sales
304

 
475

 
464

Selling, general and administrative
29,799

 
25,971

 
29,088

 
151,126

 
148,044

 
169,306

INCOME FROM OPERATIONS
46,911

 
54,830

 
71,152

Interest expense
(25,222
)
 
(28,213
)
 
(29,143
)
Interest income
193

 
362

 
132

Foreign currency exchange gains (losses)
(1,974
)
 
(2,222
)
 
681

Loss on early extinguishment of debt

 
(1,504
)
 

Gain on sale of marketable securities

 

 
230

Other income
63

 
488

 
780

Income before income taxes
19,971

 
23,741

 
43,832

Provision (benefit) for income taxes
10,293

 
(89,940
)
 
6,782

NET INCOME
$
9,678

 
$
113,681

 
$
37,050

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



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Table of Contents



SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
 
  
Year Ended December 31,
 
2014
 
2013
 
2012
Net income
$
9,678

 
$
113,681

 
$
37,050

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

 

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

 

 
(230
)
Foreign currency translation adjustments
(12,081
)
 
(9,952
)
 
2,969

Comprehensive income (loss)
$
(2,403
)
 
$
103,729

 
$
39,757

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


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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, 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

Amortization of stock-based compensation costs

 

 
536

 

 

Net income

 

 

 
9,678

 

Foreign currency translation adjustments

 

 

 

 
(12,081
)
Balance, December 31, 2014
100

 
$

 
$
400,177

 
$
(148,776
)
 
$
1,688

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


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


  
Year Ended December 31,
 
2014
 
2013
 
2012
Cash flows from operating activities:
 
 
 
 
 
Reconciliation of net income to net cash provided by operating activities:
 
 
 
 
 
Net income
$
9,678

 
$
113,681

 
$
37,050

Depreciation and amortization
121,023

 
121,598

 
139,754

Loss on early extinguishment of debt

 
1,504

 

Deferred income tax provision (benefit)
9,273

 
(86,863
)
 
1,222

Foreign currency exchange losses (gains)
1,974

 
2,222

 
(681
)
Amortization of deferred financing costs
1,090

 
1,246

 
2,044

Amortization of stock-based compensation
536

 
869

 
761

Amortization of favorable facility lease

 

 
393

Decrease in allowance for doubtful accounts
(337
)
 
(300
)
 
(461
)
Non-cash other loss (income)
15

 
(377
)
 
(208
)
Non-cash revenue
(1,071
)
 
(2,486
)
 
(8,518
)
Gain on sale of marketable securities

 

 
(230
)
Decrease (increase) in receivables
(12,199
)
 
26,915

 
(8,365
)
Decrease (increase) in other assets
(405
)
 
586

 
(43
)
Increase (decrease) in deferred revenue
(6,960
)
 
(10,093
)
 
6,520

Increase (decrease) in accounts payable and other liabilities
1,728

 
(20,572
)
 
2,243

Net cash provided by operating activities
124,345

 
147,930

 
171,481

Cash flows from investing activities:
 
 
 
 
 
Cash invested in seismic data
(93,682
)
 
(144,557
)
 
(183,244
)
Cash paid to acquire property, equipment and other
(1,961
)
 
(936
)
 
(1,422
)
Net proceeds from sale of marketable securities

 

 
230

Cash from sale of property, equipment and other

 
61

 
90

Advances to Seitel Holdings, Inc.
(13
)
 
(256
)
 
(13
)
Net cash used in investing activities
(95,656
)
 
(145,688
)
 
(184,359
)
Cash flows from financing activities:
 
 
 
 
 
Issuance of 9½% Senior Notes

 
250,000

 

Repayment of 9.75% Senior Notes

 
(275,000
)
 

Principal payments on notes payable

 
(29
)
 
(66
)
Principal payments on capital lease obligations
(249
)
 
(248