TMCnet News
SAEXPLORATION HOLDINGS, INC. - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS(Edgar Glimpses Via Acquire Media NewsEdge) The following discussion of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and notes to those statements included in this Form 10-Q. This discussion contains forward-looking statements that involve risks and uncertainties. Please see the sections entitled "Forward-Looking Statements" in this Form 10-Q, the section entitled "Risk Factors" in our Form 10-K filed with the SEC on April 3, 2014, and the section entitled "Item 1A. Risk Factors" in this Form 10-Q. Amounts are in thousands, except for share amounts and as otherwise noted. Introduction We are an internationally-focused oilfield services company offering a full range of vertically-integrated seismic data acquisition and logistical support services in Alaska, Canada, South America, Southeast Asia and Africa to our customers in the oil and natural gas industry. We were initially formed on February 2, 2011 as a blank check company in order to effect a merger, capital stock exchange, asset acquisition or other similar business combination with one or more business entities. On June 24, 2013, the Merger with Former SAE was consummated, at which time our business became the business of Former SAE. The Merger was accounted for as a reverse acquisition in accordance with GAAP. Under this method of accounting, we were treated as the "acquired" company for financial reporting purposes. This determination was primarily based on Former SAE comprising the ongoing operations of the combined entity, Former SAE senior management comprising the senior management of the combined company, and the Former SAE common stockholders having a majority of the voting power of the combined entity. In accordance with guidance applicable to these circumstances, the Merger was considered to be a capital transaction in substance. Accordingly, for accounting purposes, the Merger was treated as the equivalent of Former SAE issuing stock for our net assets, accompanied by a recapitalization. Our net assets were stated at fair value, with no goodwill or other intangible assets recorded. Operations prior to the Merger are those of Former SAE. The equity structure after the Merger reflects our equity structure. Overview Our services include the acquisition of 2D, 3D, time-lapse 4D and multi-component seismic data on land, in transition zones between land and water and offshore in depths of up to 5,000 feet. In addition, we offer a full suite of logistical support and in-field processing services. Our customers include major integrated oil companies, national oil companies and independent oil and gas exploration and production companies. Our services are primarily used by our customers to identify and analyze drilling prospects and to maximize successful drilling, making demand for such services dependent upon the level of customer spending on exploration, production, development and field management activities, which is influenced by the fluctuation in oil and natural gas commodity prices. Demand for our services is also impacted by long-term supply concerns based on national oil policies and other country-specific economic and geo-political conditions. We have expertise in logistics and focus upon providing a complete service package, particularly in our international operations, which allows efficient movement into remote areas, giving us what we believe to be a strategic advantage over our competitors and providing us with opportunities for growth. Many of the areas of the world where we work have limited seasons for seismic data acquisition, requiring high utilization of key personnel and redeployment of equipment from one part of the world to another. All of our remote area camps, drills and support equipment are easily containerized and made for easy transport to locations anywhere in the world. As a result, if conditions deteriorate in a current location or demand rises in another location, we are able to quickly redeploy our crews and equipment to other parts of the world. By contrast, we tend to subcontract out more of our services in North America than in other regions, and our North American revenues tend to be more dependent upon data acquisition services rather than our full line of services. While our revenues from services are mainly affected by the level of customer demand for our services, operating revenue is also affected by the bargaining power of our customers relating to our services, as well as the productivity and utilization levels of our data acquisition crews. Our logistical expertise can be a mitigating factor in service price negotiation with our customers, allowing us to maintain larger margins in certain regions of the world, particularly in the most remote or most challenging climates of the world. Factors impacting the productivity and utilization levels of our crews include permitting delays, downtime related to inclement weather, decrease in daylight working hours during winter months, time and expense of repositioning crews, the number and size of each crew, and the number of recording channels available to each crew. We have the ability to optimize the utilization of personnel and equipment, which is a key factor to stabilizing margins in the various regions in which we operate. Specifically, we are investing in equipment that is lighter weight and more easily shipped between the different regions. The ability to reduce both the costs of shipment and the amount of shipping time increases our operating margins and utilization of equipment. Similar logic applies to the utilization of personnel. We focus on employing field managers who are mobile and have the expertise and knowledge of many different markets within our operations. This allows for better timing of operations and the ability of management staff to run those operations while at the same time minimizing personnel costs. An added benefit of a highly mobile field management team is better internal transfer of skill and operational knowledge and the ability to spread operational efficiencies rapidly between the various regions. 14 Our contracts are either term (variable pricing) or turnkey (fixed price). Revenue is recognized on the term contracts at the rate provided in the particular contract. As related to turnkey contracts, we recognize revenue based upon measurable outputs from the project. Generally, these outputs are verified by a customer representative in the field on a daily or weekly basis. Once the progress from the field is acknowledged by the customer representative, the information is then used to assemble the monthly invoices. Generally the choice of whether to subcontract out services depends on the expertise available in a certain region and whether that expertise is more efficiently obtained through subcontractors or by using our own labor force. For the most part, services are subcontracted within North America and our personnel are used in other regions where we operate. When subcontractors are used, we manage them and require that they comply with our work policies and QHSE objectives. Our customers continue to request increased recording channel capacity on a per crew or project basis in order to produce higher resolution images, to increase crew efficiencies and to allow us to undertake larger scale projects. In order to meet these demands, we continue to invest in additional land and marine channels, and routinely deploy a variable number of channels with multiple crews in an effort to maximize asset utilization and meet customer needs. We believe that increased channel counts and more flexibility of deployment will result in increased crew efficiencies, which we believe should translate into higherrevenues and margins. Contracts We conduct data acquisition services under master service agreements with our customers that set forth certain obligations of our customers and us. A supplemental agreement setting forth the terms of a specific project, which may be cancelled by either party on short notice, is entered into for every data acquisition project. The supplemental agreements are either "turnkey" agreements that provide for a fixed fee to be paid to us for each unit of data acquired, or "term" agreements that provide for a fixed hourly, daily or monthly fee during the term of the project. Turnkey agreements generally mean more profit potential, but involve more risks due to potential crew downtimes or operational delays. We attempt to negotiate on a project-by-project basis some level of weather downtime protection within the turnkey agreements. Under term agreements, we are ensured a more consistent revenue stream with improved protection from crew downtime or operational delays, but with a decreased profit potential. How We Generate Revenues We provide a full range of seismic data acquisition services, including infield processing services, and related logistics services. We currently provide our services on only a proprietary basis to our customers and the seismic data acquired is owned by our customers once acquired. Our seismic data acquisition and logistics services include the following: Program Design, Planning and Permitting. A seismic survey is initiated at the time the customer requests a proposal to acquire seismic data on its behalf. We employ an experienced design team, including geophysicists with extensive experience in 2D, 3D and time-lapse 4D survey design, to recommend acquisition parameters and technologies to best meet the customer's exploration objectives. Our design team analyzes the request and works with the customer to put an operational, personnel and capital resource plan in place to execute the project. Once a seismic program is designed, we assist the customer in obtaining the necessary permits from governmental authorities and access rights of way from surface and mineral estate owners or lessees where the survey is to be conducted. It is usually our permitting crew that is first to engage with the local residents and authorities. We believe our knowledge of the local environment, cultural norms and excellent QHSE track record enable us to engender trust and goodwill with the local communities, which our customers are able to leverage over the longer exploration cycle in the area. Camp Services. We have developed efficient processes for assembling, operating and disassembling field camps in challenging and remote project locations. We operate our camps to ensure the safety, comfort and productivity of the team working on each project and to minimize our environmental impact through the use of wastewater treatment, trash management, water purification, generators with full noise isolation and recycling areas. 15 In areas like South America and Papua New Guinea, logistical support needs to be in place to establish supply lines for remote jungle camps. To insure the quality of services delivered to these remote camps, we own ten supply and personnel river vessels to gain access to remote jungle areas. We also have five jungle camps and a series of 40 fly camps that act as advance camps from the main project camp. Each of these jungle base camps contains a full service medical facility complete with doctors and nurses in the remote chance we need to stabilize any potential injuries for medical transport. The camps are equipped with full meal kitchens held to high standards of cleanliness, sleeping and recreational quarters, power supply, communications links, air support, water purification systems, black water purification systems, offices, repair garages, fuel storage and many more support services. Survey and Drilling. In a typical seismic recording program, the first two stages of the program are survey and drilling. Once the permitting is completed, our survey crews enter the project areas and begin establishing the source and receiver placements in accordance with the survey design agreed to by the customer. The survey crew lays out the line locations to be recorded and, if explosives are being used, identifies the sites for shot-hole placement. The drilling crew creates the holes for the explosive charges that produce the necessary acoustical impulse. The surveying and drilling crews are usually employed by us but may be third party contractors depending on the nature of the project and its location. Generally the choice of whether to subcontract out services depends on the expertise available in a certain region and whether that expertise is more efficiently obtained through subcontractors or by using our own labor force. For the most part, services are subcontracted within Alaska and Canada and our personnel are used in other regions where we operate. When subcontractors are used, we manage them and require that they comply with our work policies and QHSE objectives. In Alaska and Canada, the surveying and drilling crews are typically provided by third party contractors but are supervised by our personnel. In Alaska and Canada, our vibroseis source units consist of the latest source technology, including eight AHV IV 364 Commander Vibrators and six environmentally friendly IVI mini vibrators, complete with the latest Pelton DR electronics. In South America and Southeast Asia, we perform our own surveying and drilling, which is supported by up to 200 drilling units, including people portable, low impact self-propelled walk behind, track driven and heli-portable deployed drilling rigs. Our senior drilling staff has a combined work experience of over 50 years in some of the most challenging environments in the world. On most programs there are multiple survey and drilling crews that work at a coordinated pace to remain ahead of the data recording crews. Recording. We use equipment capable of collecting 2D, 3D, time-lapse 4D and multi-component seismic data. We utilize vibrator energy sources or explosives depending on the nature of the program and measure the reflected signals with strategically placed sensors. Onshore, geophones are manually buried, or partially buried, to ensure good coupling with the surface and to reduce wind noise. Offshore, the reflected signals are recorded by either hydrophones towed behind a survey vessel or by geophones placed directly on the seabed. We increasingly employ ocean bottom nodes positioned by remote operated vehicles on the seafloor in our marine acquisition operations. We have available over 29,500 owned land and marine seismic recording channels with the ability to access additional equipment through rental or long-term leasing sources. All of our systems record equivalent seismic information but vary in the manner by which seismic data is transferred to the central recording unit, as well as their operational flexibility and channel count expandability. We utilize 11,500 channels of Sercel 428/408 equipment, 6,000 channels of Fairfield Land Nodal equipment and 2,000 units of Fairfield Ocean Bottom Nodal equipment and 10,000 channels of Oyo GSR equipment. We have made significant capital investments to increase the recording capacity of our crews by increasing channel count and the number of energy source units we operate. This increase in channel count demand is driven by customer needs and is necessary in order to produce higher resolution images, increase crew efficiencies and undertake larger scale projects. In response to project-based channel requirements, we routinely deploy a variable number of channels with a variable number of crews in an effort to maximize asset utilization and meet customer needs. When recording equipment is at or near full utilization, we utilize rental equipment from strategic suppliers to augment our existing inventories. We believe we will realize the benefit of increased channel counts and flexibility of deployment through increased crew efficiencies, higher revenues and increased margins. During the past three years, we dedicated a significant portion of our capital investment to purchasing and leasing wireless recording systems rather than the traditional wired systems. We utilize this equipment as primarily stand-alone recording systems, but on occasion it is used in conjunction with cable-based systems. The wireless recording systems allow us to gain further efficiencies in data recording and provide greater flexibility in the complex environments in which we operate. In addition, we have realized increased crew efficiencies and lessened the environmental impact of our seismic programs due to the wireless recording systems because they require presence of fewer personnel and less equipment in the field. We believe we will experience continued demand for wireless recording systems in the future. 16 We also utilize multi-component recording equipment on certain projects to further enhance the quality of data acquired and help our customers enhance their development of producing reservoirs. Multi-component recording involves the collection of different seismic waves, including shear waves, which aids in reservoir analysis such as fracture orientation and intensity in shales and allows for more descriptive rock properties. We maintain a surplus of equipment, and augment our needs with leased equipment from time to time, to provide additional operational flexibility and to allow us to quickly deploy additional recording channels and energy source units as needed to respond to customer demand. Reclamation. We have experienced teams responsible for reclamation of the areas where work has been performed so as to minimize the environmental footprint from the seismic program. These programs can include reforestation or other activities to restore the natural landscape at our worksites. In-field Processing. Our knowledgeable and experienced team provides our customers with superior quality in-field processing. We believe that our strict quality control processes meet or surpass industry-established standards, including identifying and analyzing ambient noise, evaluating field parameters and employing obstacle-recovery strategies. Using the latest technology, our technical and field teams electronically manage customer data from the field to the processing office, minimizing time between field production and processing. All of the steps employed in our in-field processing sequence are tailored to the particular customer project and objectives. Results of Operations Overview The following discussion is intended to assist in understanding our financial position at June 30, 2014, and our results of operations for the three and six months ended June 30, 2014. Financial and operating results for the three months ended June 30, 2014 include: • Revenues from services for the three months ended June 30, 2014 of $103,141 compared to $42,380 in 2013. • Gross margin for the three months ended June 30, 2014 decreased to 17.8% from 22.9% in 2013. • Operating income for the three months ended June 30, 2014 was $7,900 compared to operating income of $2,675 in 2013. • Net income for the three months ended June 30, 2014 of $761 compared to net loss of $(1,319) in 2013. • Adjusted EBITDA for the three months ended June 30, 2014 increased to $13,014 compared to $7,877 for 2013. • Cash and cash equivalents totaled $13,363 as of June 30, 2014 compared to $28,521 as of June 30, 2013. Three months ended June 30, 2014, compared to three months ended June 30, 2013 Our operating results for the three months ended June 30, 2014 and 2013 are highlighted below (amounts in thousands): Three Months Ended June 30, 2014 % of Revenue 2013 % of Revenue Revenue from services: North America $ 48,342 46.9 % $ 12,078 28.5 % South America 54,799 53.1 % 23,668 55.8 % South East Asia - 0.0 % 6,634 15.7 % Total revenue 103,141 100.0 % 42,380 100.0 % Gross profit 18,381 17.8 % 9,684 22.9 % Selling, general and administrative expenses 9,956 9.7 % 6,127 14.5 % Depreciation and amortization 259 0.3 % 257 0.6 % Other 266 0.3 % 625 1.5 % Income from operations $ 7,900 7.7 % $ 2,675 6.3 % 17 Six months ended June 30, 2014, compared to six months ended June 30, 2013Our operating results for the six months ended June 30, 2014 and 2013 are highlighted below (amounts in thousands): Six Months Ended June 30, 2014 % of Revenue 2013 % of Revenue Revenue from services: North America $ 79,941 41.9 % $ 53,389 42.0 % South America 110,112 57.7 % 55,227 43.4 % South East Asia 750 0.4 % 18,530 14.6 % Total revenue 190,803 100.0 % 127,146 100.0 % Gross profit 38,089 20.0 % 29,682 23.3 % Selling, general and administrative expenses 19,336 10.1 % 13,593 10.7 % Depreciation and amortization 586 0.3 % 522 0.4 % Other 288 0.2 % 686 0.5 % Income from operations $ 17,879 9.4 % $ 14,881 11.7 % Revenue from services. North America: Revenues in North America for the three and six months ended June 30, 2014 increased by $36,264 or 300.2% and $26,552 or 49.7%, respectively, compared to $12,078 and $53,389, respectively, for three and six months ended June 30, 2013. The increase in revenues was due mainly to increased revenues in Alaska during 2014 resulting from an overall increase in seismic activity and market share in the North Slope region compared to 2013. The addressable market in the North Slope region of Alaska experienced significant growth during the 2014 winter season as a result of favorable market and regulatory conditions for oil and gas producers. South America: Revenues in South America for the three and six months ended June 30, 2014 increased by $31,131 or 131.5% and $54,885 or 99.4%, respectively, compared to $23,668 and $55,227, respectively, for three and six months ended June 30, 2013. The increase in revenues during 2014 was due mainly to a major project in Bolivia and overall increased exploration activity within complex regions of South America. Southeast Asia: Revenues in Southeast Asia for the three and six months ended June 30, 2014 decreased by $6,634 or 100.0% and $17,780 or 96.0%, respectively, compared to $6,634 and $18,530, respectively, for three and six months ended June 30, 2013. The decrease in revenue for Southeast Asia was due primarily to Papua New Guinea and Malaysia, which had major projects during 2013 compared to no activity in 2014. Southeast Asia remains a burgeoning, yet competitive market for shallow-water seismic activity. Gross profit. Gross profit was $18,381, or 17.8% of revenues, for the three months ended June 30, 2014, compared to gross profit of $9,684, or 22.9% of revenues, for the three months ended June 30, 2013. For the six months ended June 30, 2014, gross profit was $38,089, or 20.0% of revenues, compared to gross profit of $29,682, or 23.3% of revenues, for the six months ended June 30, 2013. Factors contributing to the reduction of gross profit as a percentage of revenue during the three and six month periods were: • The low level of seismic activity in Canada during the three months ended March 31, 2014, which inflicted adverse pressure on margins for the period; • The timing of the completion of certain projects in South America during the three months ended June 30, 2014; and • Unfavorable conditions during the three months ended June 30, 2014 on the most complex seismic project the Corporation has completed in Bolivia, which was successfully performed during the six months ended June 30, 2014. 18 Selling, general and administrative expenses. For the three months ended June 30, 2014, selling, general and administrative ("SG&A") expenses increased by $3,829 to $9,956 or 9.7% of revenues compared to $6,127 or 14.5% of revenues for the three months ended June 30, 2013. For the six months ended June 30, 2014, SG&A increased by $5,743 to $19,336 or 10.1% of revenues compared to $13,593 or 10.7% of revenues for the six months ended June 30, 2013. The decrease in SG&A expenses as a percentage of revenues was due to the overall increase in revenue and the benefits from our previously planned scaling of internal infrastructure built to manage our continuing growth. Additional costs were incurred during the first six months of 2014 as a result of being a public company, including hiring additional accounting and financial staff, the fees and expenses related to making public filings during the three and six months ended June 30, 2014, and the additional costs of outside consultants, attorneys and auditors to satisfy our increased obligations as a public company and to offer our senior secured notes. Interest expense. Interest expense, net, increased to $4,141 for the three months ended June 30, 2014, versus $3,427 for the three months ended June 30, 2013. For the six months ended June 30, 2014, interest expense, net, increased to $8,171, compared to $6,812 for the six months ended June 30, 2013. This increase was as a result of the amortization of additional deferred financing costs associated with Amendment No. 2 and Amendment No. 3 dated June 24, 2013 and October 31, 2013, respectively, related to our 2012 Credit Agreement and interest related to the notes payable to Former SAE stockholders. Change in fair value of notes payable to Former SAE stockholders. As of June 30, 2014, the fair values of the notes payable to Former SAE stockholders were derived using a probability weighted approach based upon the risk of the refinancing discussed in Note 11. Based on the available information as of June 30, 2014, the refinancing was expected to close on July 2, 2014 subject to customary closing conditions. As a result, we determined that the payoff amount represented the fair value as of June 30, 2014. The total change in the fair value of the Former SAE stockholders' notes for the three and six months ended June 30, 2014 was $4,587 and $5,094, respectively. Net income (loss) attributable to the Corporation. Net income (loss) attributable to the Corporation for the three months ended June 30, 2014 was a net loss of $(146) compared to net loss of $(1,319) for the three months ended June 30, 2013. For the six months ended June 30, 2014, net income attributable to the Corporation was $552 compared to $4,543 for the six months ended June 30, 2013. The increase in net income for the three months ended June 30, 2014 was due to a number of factors including: • Foreign exchange gains for the three months ended June 30, 2014 of $494 compared to foreign exchange losses of $842 for the three months ended June 30, 2013; and • Other income for the three months ended June 30, 2014 of $545 compared to other expense of $1,308 for the three months ended June 30, 2013. Due primarily to the fact that the Corporation incurred approximately $1,000 in third-party debt-related fees for the three months ended June 30, 2013 and no compatible cost in the three months ended June 30, 2014. The decline in net income for the six months ended June 30, 2014 was due to a number of factors including: • Higher tax provision due to the impact of the valuation allowance recorded against the U.S. net deferred tax assets; • Higher operating expenses due to reasons cited above; • Unrealized loss on the change in the fair value of the notes payable to Former SAE stockholders resulting from the pending retirement of the notes in connection with the senior secured notes offering; • Higher interest expense for the three and six months ended June 30, 2014; and • Higher income attributable to joint venture. Adjusted EBITDA.For the three months ended June 30, 2014, adjusted EBITDA was $13,014 compared to $7,877 for the three months ended June 30, 2013. For the six months ended June 30, 2014, adjusted EBITDA was $26,994 compared to $23,721 for the six months ended June 30, 2013. The increase was due mainly to higher revenue earned during the periods in conjunction with better cost control at the corporate level. Working capital. At June 30, 2014, working capital was $39,202 compared to $50,263 at June 30, 2013. 19 Liquidity and Capital Resources Cash Flows. Cash provided by operations for the first six months of 2014 was $828, compared to cash provided by operations of $1,719 for the first six months of 2013, a decrease of $891. This decrease was due mainly to a decrease in total net income from $4,543 for the six months ended June 30 2013 to $2,245 for the six months ended June 30 2014. Changes in operating assets and liabilities were cash uses of $(16,917) for the six months ended June 30, 2014 and cash uses of $(13,638) for the six months ended June 30, 2013. Working Capital. Working capital as of June 30, 2014 was $39,202 compared to $27,111 as of December 31, 2013. The increase in working capital in the first half of 2014 was principally the result of an increase in accounts receivable of $30,452 partially offset by an increase in accounts payable of $19,608. Capital Expenditures. Our focus on providing leading edge technology will be at the forefront of our capital expenditure plans in the coming years, which investments will continue to strengthen our position and growth in the global oil and gas exploration services market. During the last three years, in line with our focus on wireless land data acquisition, we purchased a cableless seismic data acquisition system which allows up to three crews to operate under the system at the same time. Following customer needs for higher density land programs using a single point receiver application and to answer the demand for conventional and unconventional oil and gas exploration, we purchased high sensitivity geophones and two types of vibrators, further strengthening our position as a full solution provider for land data acquisition methods and technologies. Additional equipment investments were made for ongoing operations in Alaska in order to increase efficiency. We also invested in cable equipment in order to provide customers in Latin America with cable systems as wireless technology is slower to take hold in that market. Focusing on worldwide oil and gas markets, we will continue to employ and expand our wireless equipment on a worldwide basis while maintaining the ability to provide services to the still existing cable markets. Our capital purchases have and will allow us to take advantage of all aspects of the geophysical exploration services market, ranging from land, marine and transition zone data acquisition; 2D, 3D, 4D and multi-component data acquisition; and use of different methods to acquire data such as using vibroseis (vibrating) and impulsive sources; as well as vertical seismic profiling and reservoir monitoring. Investments in expanding further into our South America and Southeast Asia markets will also focus upon surveying, drilling and base camp operations. For the three and six months ended June 30, 2014, our capital expenditures totaled $2,281 and $4,406, respectively. These capital expenditures consisted primarily of camp and drilling equipment purchases in Peru and Colombia in line with our focus on South American operations and a combination of mechanical equipment, computer equipment and electronics associated with our wireless strategy in Southeast Asia and North and South America. Total capital investment for equipment in the three and six months ended June 30, 2013 was $939 and $2,688, respectively. Financing. In connection with the Merger, we executed a Joinder to the 2012 Credit Agreement, pursuant to which we joined, in the same capacity as Former SAE, the 2012 Credit Agreement. The 2012 Credit Agreement interest rate was 13.5%, of which 2.5% could be paid-in-kind ("PIK"), at our election, by adding interest back to the principal amount under the 2012 Credit Agreement. Our management exercised the PIK option in 2013 and first half of 2014. At June 30, 2014 and December 31, 2013, we had cumulative PIK interest obligations of $1,022 and $2,040, respectively. Repayment of the 2012 Credit Agreement began on December 31, 2012, with a payment of $100, and additional principal payments of $200 are due at the end of every calendar quarter through September 30, 2016, with the remaining balance due on November 28, 2016. The 2012 Credit Agreement provided for certain prepayment penalties if we prepaid any portion of the outstanding principal balance prior to its due date that decline over the term of the agreement. At June 30, 2014, and December 31, 2013, we had $81,759 and $81,137, respectively, outstanding under the 2012 Credit Agreement. At June 30, 2014, and December 31, 2013, we were in compliance with all covenants under the 2012 Credit Agreement, except that our entry into the purchase agreement for the senior secured notes on June 25, 2014, constituted a technical default under the 2012 Credit Agreement, requiring the use of the proceeds of the issuance of the senior secured notes to repay all amounts due under the 2012 Credit Agreement. We also note that we had an obligation under our 2012 Credit Agreement to deliver annual audited consolidated financial statements within 90 days following the end of our fiscal year. We were not able to deliver such financial statements until the completion of our 2013 financial statement audit and the filing of our Annual Report on Form 10-K on April 3, 2014. The failure to timely deliver such financial statements resulted in a technical event of default under our 2012 Credit Agreement. The remedies provided to the lenders in the 2012 Credit Agreement for an event of default were only available if the event of default was continuing. The default ceased to be continuing upon delivery of our annual audited financials on April 3, 2014. All amounts outstanding under the 2012 Credit Agreement were repaid on July 2, 2014 from the proceeds of the issuance of the senior secured notes, and the 2012 Credit Agreement was terminated. At the Closing of the Merger, we issued a promissory note in the principal amount of $17,500 to CLCH, as a representative of the Former SAE stockholders, as Merger consideration to the Former SAE stockholders. The note is unsecured, is subordinate to the borrowings outstanding under the 2012 Credit Agreement, carries an annual interest rate of 10% and is due and payable in full on June 24, 2023. Interest payments are due semi-annually under the note, subject to certain restrictions under the 2012 Credit Agreement. In the third quarter of 2013, CLCH, Seismic Management Holdings Inc. and Brent Whiteley agreed to allow us to withhold the interest payments payable to them under the note in respect of their individual interests as stockholders of Former SAE until such payments are permitted to be made under the 2012 Credit Agreement, which is expected to be in the fourth quarter of 2014. On July 2, 2014, the amount owed under the 2012 Credit Agreement was paid as described below. As a result, the above restrictions are no longer in place. 20 On July 2, 2014, we issued senior secured notes totaling $150,000 in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to non-U.S. persons in offshore transactions pursuant to Regulation S under the Securities Act. The proceeds of these senior secured notes were used to repay the amounts owed under the 2012 Credit Agreement and the notes payable to Former SAE stockholders and will also be used to pay related fees and expenses and for general corporate purposes. See discussion of the senior secured notes in Note 11, Subsequent Events, to the consolidated financial statements included in Part I, Item 1 of this quarterly report onForm 10-Q. Use of EBITDA (Non-GAAP measure) as a Performance Measure We use an adjusted form of EBITDA to measure period over period performance, which is not derived in accordance with GAAP. Adjusted EBITDA is defined as net income (loss) plus interest expense, less interest income, plus unrealized loss on change in fair value of notes payable to Former SAE stockholders, plus income taxes, plus depreciation and amortization, plus non-recurring major expenses outside of operations, plus non-recurring one-time expenses and unrealized foreign exchange gain or loss. Our management uses adjusted EBITDA as a supplemental financial measure to assess: • the financial performance of our assets without regard to financing methods, capital structures, taxes, historical cost basis or non-recurring expenses; • our liquidity and operating performance over time in relation to other companies that own similar assets and calculate EBITDA in a similar manner; and • the ability of our assets to generate cash sufficient to pay potential interest cost. We consider adjusted EBITDA as presented below to be the primary measure of period-over-period changes in our operational cash flow performance. The terms EBITDA and adjusted EBITDA are not defined under GAAP, and we acknowledge that these are not a measure of operating income, operating performance or liquidity presented in accordance with GAAP. When assessing our operating performance or liquidity, investors and others should not consider this data in isolation or as a substitute for net income (loss), cash flow from operating activities or other cash flow data calculated in accordance with GAAP. In addition, our calculation of adjusted EBITDA may not be comparable to EBITDA or similarly titled measures utilized by other companies since such other companies may not calculate EBITDA in the same manner. Further, the results presented by adjusted EBITDA cannot be achieved without incurring the coststhat the measure excludes. The computation of our adjusted EBITDA (a non-GAAP measure) from net income (loss), the most directly comparable GAAP financial measure, is provided in the table below (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 Net income (loss) $ 761 $ (1,319 ) $ 2,245 $ 4,543 Depreciation, amortization 3,693 3,683 7,546 7,458 Interest expense, net 4,141 3,427 8,171 6,812 Unrealized loss on change in fair value of notes payable to Former SAE stockholders 4,587 (1) - 5,094 (1) - Provision (benefit) for income taxes (550 ) (1,583 ) 3,262 782 Foreign exchange (gain) loss, net (494 ) 842 (200 ) 1,299 Non-recurring expense 876 (3) 2,827 (2) 876 (3) 2,827 (2) Adjusted EBITDA $ 13,014 $ 7,877 $ 26,994 $ 23,721 21 (1) As of June 30, 2014, the fair values of the notes payable to Former SAE stockholders were derived using a probability weighted approach based upon the risk of the refinancing discussed in Note 11. Based on the available information as of June 30, 2014, the refinancing was expected to close on July 2, 2014 subject to customary closing conditions. As a result, we determined that the payoff amount represented the fair value as of June 30, 2014. The total change in the fair value of the Former SAE stockholders' notes for the three and six months ended June 30, 2014 was $4,587 and $5,094, respectively. (2) Principally third-party financing costs, share-based compensation expense related to the accelerated vesting of Former SAE's restricted shares in connection with the Merger, costs associated with the Merger, and one-time severance costs related to the reduction of staff in Colombia. (3) Principally the settlement of disputed fees with a former financial advisor to the Corporation. As of June 30, 2014, the Corporation recorded a liability of $657 related to this settlement. A reconciliation of adjusted EBITDA to net cash (used in) provided by operating activities and the three components of cash flows are provided in the table below (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 Adjusted EBITDA $ 13,014 $ 7,877 $ 26,994 $ 23,721 Adjustments to adjusted EBITDA which were not adjustments to net cash (used in) provided by operating activities: Interest (expense) income, net (4,141 ) (3,427 ) (8,171 ) (6,812 ) Unrealized loss on change in fair value of notes payable to Former SAE stockholders (4,587 ) - (5,094 ) - Foreign exchange gain (loss), net 494 (842 ) 200 (1,299 ) Income tax benefit (expense) 550 1,583 (3,262 ) (782 ) Non-recurring expense (876 ) (2,827 ) (876 ) (2,827 ) Adjustments to net cash (used in) provided by operating activities which were not adjustments to adjusted EBITDA: Deferred income taxes (60 ) 71 48 66 Changes in operating assets and liabilities (8,279 ) (12,284 ) (16,917 ) (13,638 ) Unrealized loss on change in fair value of notes payable to Former SAE stockholders 4,587 - 5,094 - Payment-in-kind interest 515 507 1,022 995 Share-based compensation - 1,043 - 1,100 Amortization of loan issuance costs 751 472 1,502 1,092 Loss on disposal of property and equipment 266 42 288 103 Net cash (used in) provided by operating activities $ 2,234 $ (7,785 ) $ 828 $ 1,719 Net cash (used in) provided by investing activities $ (2,209 ) $ (939 ) $ (4,334 ) $ (2,688 ) Net cash (used in) provided by financing activities $ (276 ) $ 14,557 $ (699 ) $ 14,049 22 Critical Accounting Policies There have been no changes to the critical accounting policies used in our reporting of results of operations and financial position. For a discussion of critical accounting policies see the section entitled "SAE's Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Form 10-K for fiscal year ended December 31, 2013 filed with the SEC on April 3, 2014. Recently Issued Accounting Pronouncements In April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment, which updated guidance in ASC Topic 360, Property, Plant and Equipment -Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity". The updated guidance is effective prospectively for years beginning on or after December 15, 2014, with early application permitted. The amendments in this update change the requirements for reporting discontinued operations in Subtopic 205-20. Under this updated guidance, a discontinued operation will include a disposal of a major part of an entity's operations and financial results such as a separate major line of business or a separate major geographical area of operations. The guidance raises the threshold to be a major operation but no longer precludes discontinued operations presentation where there is significant continuing involvement or cash flows with a disposed component of an entity. The guidance expands disclosures to include cash flows where there is significant continuing involvement with a discontinued operation and the pre-tax profit or loss of disposal transactions not reported as discontinued operations. The adoption of ASU 2014-08 is not expected to have a material impact on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in "Revenue Recognition (Topic 605)." ASU 2014-09 is based on the principle that revenue is recognized 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. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016, using one of two retrospective application methods. Early adoption is not permitted. We are currently reviewing this standard to assess the impact of adoption on our consolidated financial statements. In June 2014, the FASB issued ASU No. 2014-10, "Development Stage Entities (Topic 915) - Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation". The amendments in this Update remove the definition of a development stage entity from Topic 915, thereby removing the distinction between development stage entities and other reporting entities from U.S. GAAP. In addition, the amendments eliminate the requirements for development stage entities to (1) present inception-to-date information on the statements of income, cash flows, and shareholder's equity, (2) label the financial statements as those of a development stage entity, (3) disclose a description of the development stage activities in which the entity is engaged, and (4) disclose in the first year in which the entity is no longer a development stage entity that in prior years it had been in the development stage. The amendments also clarify that the guidance in Topic 275, Risks and Uncertainties, is applicable to entities that have not commenced planned principal operations. An illustration has been added to Topic 275 to illustrate how an entity that has not commenced planned principal operations may comply with the disclosure required by paragraph 275-10-50-2. Finally, the amendments also remove paragraph 810-10-15-16. Paragraph 810-10-15-16 states that a development stage entity does not meet the condition in paragraph 810-10-15-14(a) to be a variable interest entity (VIE) if (1) the entity can demonstrate that the equity invested in the legal entity is sufficient to permit it to finance the activities it is currently engaged in and (2) the entity's governing documents and contractual arrangements allow additional equity investments. Under the amendments, all entities within the scope of the Variable Interest Entities Subsections of Subtopic 810-10, Consolidation-Overall, would be required to evaluate whether the total equity investment at risk is sufficient using the guidance provided in paragraphs 810-10-25-45 through 25-47, which requires both qualitative and quantitative evaluations. This Accounting Standards Update is the final version of Proposed Accounting Standards Update 2013-320-Development Stage Entities (Topic 915), which has been deleted. The adoption of ASU 2014-10 is not expected to have a material impact on our consolidated financial statements. In June 2014, the FASB issued ASU No.2014-11, "Transfers and Servicing (Topic 860) - Repurchase-to-Maturity Transactions, Repurchase Financings, and Disclosures". The amendments in this Update require that repurchase-to-maturity transactions be accounted for as secured borrowings consistent with the accounting for other repurchase agreements. In addition, the amendments require separate accounting for a transfer of a financial asset executed contemporaneously with a repurchase agreement with the same counterparty (a repurchase financing), which will result in secured borrowing accounting for the repurchase agreement. The amendments require an entity to disclose information about transfers accounted for as sales in transactions that are economically similar to repurchase agreements, in which the transferor retains substantially all of the exposure to the economic return on the transferred financial asset throughout the term of the transaction. In addition the amendments require disclosure of the types of collateral pledged in repurchase agreements, securities lending transactions, and repurchase-to-maturity transactions and the tenor of those transactions. This Accounting Standards Update is the final version of Proposed Accounting Standards Update 2013-210-Transfers and Servicing (Topic 860), which has been deleted. The adoption of ASU 2014-11 is not expected to have a material impact on our consolidated financial statements. In June 2014, the FASB issued ASU No. 2014-12, "Compensation-Stock Compensation", which updated the guidance in ASC Topic 718, "Compensation - Stock Compensation". The update is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. The amendments require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Topic 718 as it relates to awards with performance conditions that affect vesting to account for such awards. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. As indicated in the definition of vest, the stated vesting period (which includes the period in which the performance target could be achieved) may differ from the requisite service period. The adoption of ASU 2014-12 is not expected to have a material impact on our consolidated financial statements. 23 Off-Balance Sheet Arrangements We do not have any off-balance sheet arrangements. Forward-Looking Statements This report contains "forward-looking statements" within the meaning of the federal securities laws, with respect to our financial condition, results of operations, cash flows and business, and our expectations or beliefs concerning future events. These forward-looking statements can generally be identified by phrases such as we or our management "expects," "anticipates," "believes," "estimates," "intends," "plans to," "ought," "could," "will," "should," "likely," "appears," "projects," "forecasts," "outlook" or other similar words or phrases. There are inherent risks and uncertainties in any forward-looking statements. Although we believe that our expectations are reasonable, we can give no assurance that these expectations will prove to have been correct, and actual results may vary materially. Except as required by law, we undertake no obligation to update, amend or clarify any forward-looking statements to reflect events, new information or otherwise. Some of the important factors that could cause actual results to differ materially from our expectations are discussed below. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements. Factors that could cause actual results to vary materially from our expectations include the following: • fluctuations in the levels of exploration and development activity in the oil and gas industry; • substantial international business exposing us to currency fluctuations and global factors, including economic, political and military uncertainties; • intense industry competition; • need to manage rapid growth; • delays, reductions or cancellations of service contracts; • operational disruptions due to seasonality and other external factors; • crew productivity; • whether we enter into turnkey or term contracts; • limited number of customers; • credit risk related to our customers; • high fixed costs of operations; • the availability of capital resources; • ability to retain key executives; and • need to comply with diverse and complex laws and regulations. You should refer to our other periodic and current reports filed with the SEC and the risk factors from our Annual Report on Form 10-K filed with the SEC on April 3, 2014, for specific risks which would cause actual results to be significantly different from those expressed or implied by any of our forward-looking statements. It is not possible to identify all of the risks, uncertainties and other factors that may affect future results. In light of these risks and uncertainties, the forward-looking events and circumstances discussed in this report may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements. Accordingly, readers of this report are cautioned not to place undue reliance on the forward-looking statements. 24 |