Item 1B.
Unresolved Staff Comments
None.
We conduct our operations out of a number of field offices, yards, shops, terminals and other facilities principally located in Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. Each of these facilities were transferred to us from CHK at the time of the spin-off. We do not believe that any one of these facilities is individually material to our operations.
Item 3.
Item 3.
Legal Proceedings
We are subject to various legal proceedings and claims arising in the ordinary course of our business. Our management does not expect the outcome of any of these known legal proceedings, individually or collectively, to have a material adverse effect on our financial condition or results of operations.
Item 4.
Item 4.
Mine Safety Disclosures
Not applicable.
PART II. OTHER INFORMATION
Item 5.
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
Our common stock is traded on the NYSE under the symbol "SSE." On January 18, 2016, we were notified by the NYSE that the average closing price of our common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price required by the NYSE under Section 802.01C of the NYSE Listed Company Manual. The notice has no immediate impact on the listing of our common stock, which will continue to be listed and traded on the NYSE during the six-month cure period, subject to our compliance with other continued listing standards. For additional information, please read “Risk Factors - If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock” in Item 1A of this report.
The following table presents the high and low sales prices of our common stock for each quarter in 2015 and 2014:
(a)
Our common stock commenced trading on the NYSE on June 17, 2014.
As of February 12, 2016, there were 1,461 registered holders of our issued and outstanding common stock.
Dividends
No dividends were paid during the years ended December 31, 2015 and 2014.
Our debt arrangements restrict our ability to distribute dividends.
Issuer Purchases of Equity Securities
The following table presents information about repurchases of our common stock during the quarter ended December 31, 2015:
(a)
Reflects shares surrendered as payment for statutory withholding taxes upon the vesting of restricted stock issued pursuant to the Seventy Seven Energy Inc. 2014 Incentive Plan.
Equity Compensation Plan Information
Information required by this item with respect to compensation plans under which our equity securities are authorized for issuance is incorporated by reference to Part III, Item 12 of this report.
Performance Graph
The following graph and table compares the cumulative total return of a $100 investment in our common stock from July 1, 2014, the date on which our stock began trading "regular way" on the NYSE, through December 31, 2015, with the total cumulative return of a $100 investment in the Standard & Poors Stock Index and the Philadelphia Stock Exchange Oil Service Sector Index during that period.
This graph shall not be deemed to be "soliciting material" or to be "filed" with the SEC.
Item 6.
Item 6.
Selected Financial Data
The following table sets forth certain consolidated financial data for the periods presented, which has been derived from our audited consolidated financial statements and the audited consolidated financial statements of our predecessor, COO. The historical combined financial statements of COO for periods and as of dates prior to its formation on October 25, 2011 were prepared on a "carve-out" basis from CHK and are intended to represent the financial results of CHK's oilfield services operations, which is COO's accounting predecessor, for the periods presented. The selected historical financial data is not necessarily indicative of results to be expected in future periods and does not necessarily reflect what our financial position and results of operations would have been had we operated as an independent public company during periods prior to our spin-off from CHK. The selected historical financial data should be read in conjunction with Item 7
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Comparability of Historical Results
The historical results discussed in this section prior to June 30, 2014 are those of COO, which is our predecessor. The transactions in which SSE became an independent, publicly traded company, including the distribution of our common stock on June 30, 2014, are referred to collectively as the "spin-off". The historical results discussed in this section prior to the spin-off do not purport to reflect what the results of operations, financial position, or cash flows would have been had we operated as an independent public company prior to June 30, 2014 and do not give effect to certain spin-off transactions on our consolidated statements of operations. For a detailed description of the basis of presentation of the historical financial statements, please read Note 1 to our consolidated financial statements in Item 8 of this report.
Overview
We are a diversified oilfield services company that provides a wide range of wellsite services to U.S. land-based E&P customers operating in unconventional resource plays. We offer services and equipment that are strategic to our customers' oil and natural gas operations. We conduct our business through three operating segments: Drilling, Hydraulic Fracturing and Oilfield Rentals. Our operations are geographically diversified across many of the most active oil and natural gas plays in the onshore United States, including the Anadarko and Permian Basins and the Eagle Ford, Haynesville, Marcellus, Niobrara and Utica Shales.
Since commencing operations in 2001, we have actively grown and modernized our asset base. As of December 31, 2015, our marketed fleet of 91 rigs consisted of 33 Tier 1 rigs, including 22 proprietary PeakeRigs, 57 Tier 2 rigs and one Tier 3 rig. Currently, we also own 11 hydraulic fracturing fleets with an aggregate of 440,000 horsepower and a diversified oilfield rentals business. We continue to modernize our asset base and are currently building four additional PeakeRigs. For additional information regarding our business and strategies, please read "Business" in Item 1 of this report.
Cyclical Nature of Industry
We operate in a highly cyclical industry. The main factor influencing demand for oilfield services is the level of drilling and completions activity by E&P companies, which in turn depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. Demand for oil and natural gas is cyclical and is subject to large and rapid fluctuations. When oil and natural gas price increases occur, producers increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. The increased capital expenditures also ultimately result in greater production, which historically has resulted in increased supplies and reduced prices that, in turn, tends to reduce demand for oilfield services. For these reasons, our results of operations may fluctuate from quarter-to-quarter and from year-to-year. For instance, the price of crude oil has fallen significantly since mid-year 2014, as a result of robust non-OPEC supply growth led by unconventional production in the United States, weakening demand in emerging markets, and OPEC’s decision to raise its production ceiling, partly in an effort to protect its market share and drive higher cost producers out of the marketplace.
The sustained decline in commodity prices since mid-2014 has dramatically reduced the level of onshore United States drilling and completions activity and, consequently, the demand for our services. As of December 31, 2015, NYMEX WTI oil spot prices had declined to their lowest levels since 2003 and NYMEX natural gas spot prices had fallen from multi-year highs reached in early 2014. The extent and length of the current down cycle continues to be uncertain and is dependent on a number of economic, geopolitical and monetary policy factors that are outside our control. Until there is a sustained recovery in commodity prices, we expect that reduced equipment utilization levels and pricing pressure across each of our operating segments will persist. If drilling and completions activity remains at depressed levels or worsens, it will likely have a material adverse impact on our business, financial condition, cash flows and results of operations.
Although the environment in which we are operating today is challenging, we continue to be focused on maximizing value for the company. We expect to achieve this objective through execution of the following strategies:
Improve flexibility in our balance sheet and enhance our liquidity. We believe that the relatively high level of our indebtedness is having a disproportionately negative effect on the valuation of the company in the debt and equity capital markets and is limiting our ability to take advantage of our operational strengths and grow our business. As a result, we have retained restructuring advisors and are actively exploring and evaluating various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including debt repurchases, exchanges of existing debt securities
for new debt securities and exchanges or conversions of existing debt securities for new equity securities, among other options. The timing and outcome of these efforts is highly uncertain and one or more of these strategic alternatives could potentially be consummated, without the consent of any one or more of our current security holders, through voluntary bankruptcy proceedings. Although we believe that we will have adequate liquidity over the next twelve months to operate our business and to meet our cash requirements based on current market conditions, we believe that a reduction of our long-term debt is needed to improve our financial position and flexibility and to better position us to take advantage of the growth opportunities that are likely to result from the current industry downturn.
Diversify our customer base and geographic footprint. We intend to utilize our modern, high-quality assets and our deep understanding of the needs of unconventional resource developers to continue to diversify our customer base and geographic footprint. We provide extensive end-to-end complementary services aimed at reducing time spent on drilling and completion and total wellhead cost. In addition, the experience we gained as an integrated part of CHK, historically one of the most active developers of unconventional resources in the United States, makes us unique and allows us to achieve significant cost and cycle time advantages. We believe this gives us a strategic advantage and positions us well to attract new customers. It also gives us the ability to bundle our service offerings and create solutions that will allow us to move from transactional supplier to strategic partner for a number of our customers. We believe this strategy will reduce our customer concentration risk over time and create greater opportunities to benefit from the eventual recovery in oil and/or natural gas prices.
Upgrade our asset base. We intend to continue to upgrade our rigs by placing in service the new Tier 1 rigs that we are currently fabricating. As of December 31. 2015, 31 of our 33 Tier 1 rigs and 40 of our 57 Tier 2 rigs are multi-well pad-ready and able to efficiently execute our customers' drilling programs. Additionally, we had four additional contracted PeakeRigs™ under construction, one of which has been delivered and three of which are scheduled to be delivered during the remainder of 2016. We also have options for two additional PeakeRigTM deliveries in 2016 that may be exercised depending on future market conditions. We currently expect to spend approximately $100.0 million in aggregate growth and maintenance capital expenditures in 2016. We also intend to explore opportunistic acquisitions, particularly within our hydraulic fracturing segment in a manner that is complementary to our existing asset base.
Continue our industry leading safety performance. We are committed to maintaining and continually improving the safety, reliability and efficiency of our operations, which we believe is critical to attracting new customers and maintaining relationships with our current customers, regulators and the communities in which we operate. We believe we have one of the lowest Total Recordable Incidence Rate ("TRIR") as compared to our industry peers. In addition, our business goals include safety metrics, which drives continuous improvement regarding quality and safety. We have adopted and developed a management system that requires rigorous processes and procedures to facilitate our compliance with environmental regulations and policies. We also conduct internal and external assessments to verify compliance and identify areas for improvement. We work diligently to meet or exceed applicable safety and environmental regulations and we intend to continue to incorporate safety, environmental and quality principals into our operating procedures as our business grows and operating conditions change.
Backlog
We maintain a backlog of contract revenues under our contracts for the provision of drilling and hydraulic fracturing services. Our drilling and hydraulic fracturing backlogs as of December 31, 2015, which are based on existing contracts, were approximately $355.8 million and $282.7 million, respectively, with average durations of 16 months and 13 months, respectively. We calculate our drilling backlog by multiplying the day rate under our contracts by the number of days remaining under the contract. We calculate our hydraulic fracturing backlog by multiplying the (i) rate per stage, which varies by operating region and is, therefore, estimated based on current customer activity levels by region and current contract pricing, by (ii) the number of stages remaining under the contract, which we estimate based on current and anticipated utilization of our crews. With respect to our hydraulic fracturing backlog, our contracts provide for periodic adjustments of the rates we may charge for our services thereunder, which will be negotiated based on then-prevailing market pricing and may be higher or lower than the current rates we charge and utilize in calculating our backlog. Our drilling backlog calculation does not include any reduction in revenues related to mobilization or demobilization, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, many of our contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. We calculate our contract drilling early termination value assuming each rig remains stacked for the remainder of the term of the terminated contract. As a result of the foregoing, revenues could differ materially from the backlog and early termination amounts presented.
As of December 31, 2015, our revenue backlog was as follows (in millions):
As of December 31, 2015, our total contract early termination value related to our drilling backlog was as follows (in millions):
How We Evaluate Our Operations
Our management team uses a variety of tools to monitor and manage our operations in the following eight areas: (a) segment gross margin, (b) equipment maintenance performance, (c) customer satisfaction, (d) asset utilization, (e) safety performance, (f) Adjusted EBITDA, (g) Adjusted Revenues and (h) Adjusted Operating Costs.
Segment Gross Margin. We define segment gross margin as segment revenues less segment operating costs, excluding depreciation and amortization, general and administrative expenses, net gains or losses on sales of property and equipment, impairment of goodwill and impairments and other. We view segment gross margin as one of our key management tools for managing costs at the segment level and evaluating segment performance. Our management tracks segment gross margin both as an absolute amount and as a percentage of revenues compared to prior periods.
Equipment Maintenance Performance. Equipment reliability ("uptime") is an important factor to the success of our business. Uptime is beneficially impacted through preventive maintenance on our equipment. We have formal preventive maintenance procedures which are regularly monitored for compliance. Further, management monitors maintenance expenses as a percentage of revenue. This metric provides a leading indicator with respect to the execution of preventive maintenance and ensures that equipment reliability issues do not negatively impact operational uptime.
Customer Satisfaction. Upon completion of many of our services, we encourage our customers to provide feedback on the services provided. The evaluation of our performance is based on various criteria and our customer comments are indicative of their overall satisfaction level. This feedback provides us with the necessary information to reinforce positive performance and remedy negative issues and trends.
Asset Utilization. By consistently monitoring our operations' activity levels, pricing and relative performance of each of our rigs and fleets, we can more efficiently allocate our personnel and equipment to maximize revenue generation. We measure our activity levels by the total number of jobs completed by each of our drilling rigs and hydraulic fracturing fleets on a periodic basis. We also monitor the utilization rates of our drilling rigs. We define utilization of our drilling rigs as the number of rigs that have operated in the past 30 days divided by the number of rigs that have operated in the last 90 days.
Safety Performance. Maintaining a safe and incident-free workplace is a critical component of our operational success. Our management team uses both lagging and leading indicators to measure and manage safety performance. Total Recordable Incident Rate (“TRIR”), Lost Time Incident Rate (“LTIR”) and Motor Vehicle Crash Rate (“MVCR”) are key lagging indicators reviewed by management. We also review leading indicators such as safety observations, training completion, and action item completion to enhance our view of safety performance. Safety performance data is reported, tracked and trended in a centralized database, which allows us to efficiently focus our incident prevention efforts.
Adjusted EBITDA. Our primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business is Adjusted EBITDA, which we define as net income before interest expense, income tax expense, depreciation and amortization, as further adjusted to add back gains on early extinguishment of debt, impairment of goodwill, impairments and other, loss on sale of a business and exit costs, gain or loss on sale of property and equipment, non-cash stock compensation, severance-related costs, impairment of equity method investment, rent expense on buildings and real estate transferred from CHK, rig rent expense, interest income and certain other non-recurring items, such as the sale of our drilling rig relocation and logistics business, the distribution of our compression unit manufacturing and geosteering businesses to CHK as part of the spin-off, and the sale of our crude and water hauling assets to a third party. The table below shows our Adjusted EBITDA for the years ended December 31, 2015, 2014 and 2013.
Adjusted Revenues and Adjusted Operating Costs. Key financial and operating measurements that our management uses to analyze and monitor our period-over-period operating performance are "Adjusted Revenues" and "Adjusted Operating Costs", which we define as revenues and operating costs before revenues and operating costs associated with our rig relocation and logistics business and water hauling assets that were sold in the second quarter of 2015, our compression unit manufacturing and geosteering businesses that were distributed to CHK as part of the spin-off, and our crude hauling assets that were sold to a third party as part of the spin-off. Adjusted Operating Costs is further adjusted to subtract rig rent expense.
Non-GAAP Financial Measures
"Adjusted EBITDA", "Adjusted Revenues" and "Adjusted Operating Costs" are non-GAAP financial measures. Adjusted EBITDA, Adjusted Revenues and Adjusted Operating Costs as used and defined by us, may not be comparable to similarly titled measures employed by other companies and are not measures of performance calculated in accordance with generally accepted accounting principles ("GAAP").
Adjusted Revenues and Adjusted Operating Costs should not be considered in isolation or as a substitute for revenues and operating costs, respectively, prepared in accordance with GAAP. However, our management uses Adjusted Revenues and Adjusted Operating Costs to evaluate our period-over-period operating performance because our management believes these measures improve the comparability of our continuing business and for the same reasons believes these measures may be useful to an investor in evaluating our operating performance. A reconciliation of Adjusted Revenues and Adjusted Operating Costs to the GAAP measures of revenues and operating costs, respectively, is provided below in "-Results of Operations" for each period discussed.
Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. However, our management uses Adjusted EBITDA to evaluate our performance and liquidity and believes Adjusted EBITDA may be useful to an investor in evaluating our operating performance and liquidity because this measure:
•
is widely used by investors in the oilfield services industry to measure a company's operating performance without regard to items excluded from the calculation of such measure, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors;
•
is a financial measurement that is used by rating agencies, lenders and other parties to evaluate our creditworthiness; and
•
is used by our management for various purposes, including as a measure of performance of our operating entities and as a basis for strategic planning and forecasting.
There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss. Additionally, because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
On a consolidated basis, the following tables present a reconciliation of Adjusted EBITDA to the GAAP financial measures of net income and cash provided by operating activities. The following tables also present a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income for each of our operating segments.
Consolidated
(a)
Rent expense on buildings and real estate transferred from CHK as part of the spin-off is included in operating costs and general and administrative expenses on the consolidated statement of operations included in Item 8 of this report. Our operating costs include $8.0 million and $15.7 million of rent expense associated with our lease of these facilities for the years ended December 31, 2014 and 2013, respectively. Our general and administrative expenses include $0.2 million and $0.8 million of rent expense associated with our lease of these facilities for the years ended December 31, 2014 and 2013, respectively.
(b)
Rig rent expense associated with our lease of drilling rigs is included in operating costs on the consolidated statement of operations included in Item 8 of this report. As of December 31, 2014, we had repurchased all of our leased drilling rigs.
(a)
Rent expense on buildings and real estate transferred from CHK as part of the spin-off is included in operating costs and general and administrative expenses on the consolidated statement of operations included in Item 8 of this report. Our operating costs include $8.0 million and $15.7 million of rent expense associated with our lease of these facilities for the years ended December 31, 2014 and 2013, respectively. Our general and administrative expenses include $0.2 million and $0.8 million of rent expense associated with our lease of these facilities for the years ended December 31, 2014 and 2013, respectively.
(b)
Rig rent expense associated with our lease of drilling rigs is included in operating costs on the consolidated statement of operations included in Item 8 of this report. As of December 31, 2014, we had repurchased all of our leased drilling rigs.
Drilling
Hydraulic Fracturing
Oilfield Rentals
Liquidity and Capital Resources
We require capital to fund ongoing operations, including operating expenses, organic growth initiatives, investments, acquisitions and debt service. We expect our future capital needs will be provided for by cash on hand, cash flows from operations, borrowings under our credit facility and other financing transactions. We believe we will have adequate liquidity over the next twelve months to operate our business and meet our cash requirements.
As of December 31, 2015, we had cash of $130.6 million and working capital of $175.5 million. As of December 31, 2014, we had cash of $0.9 million and working capital of $208.6 million.
We have retained restructuring advisors and are actively exploring and evaluating various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including debt repurchases, exchanges of existing debt securities for new debt securities and exchanges or conversions of existing debt securities for new equity securities, among other options. The timing and outcome of these efforts is highly uncertain and one or more of these strategic alternatives could potentially be consummated, without the consent of any one or more of our current security holders, through voluntary bankruptcy proceedings. Although we believe that we will have adequate liquidity over the next twelve months to operate our business and to meet our cash requirements, based on current market conditions, we believe that a reduction of our long-term debt is needed to improve our financial position and flexibility and to better position us to take advantage of the growth opportunities that are likely to result from the current industry downturn.
Long-Term Debt
The following table presents our long-term debt as of December 31, 2015 and 2014:
(a)
Please read Note 2 to our consolidated financial statements included in Item 8 of this report.
On May 13, 2015, we entered into an incremental term supplement to the Term Loan and borrowed an additional $100.0 million in aggregate principal amount (the “Incremental Term Loan”), receiving net proceeds of $94.5 million. Borrowings under the Incremental Term Loan bear interest at our option at either (i) LIBOR, with a floor of 1.00% or (ii) the Base Rate, calculated as the greatest of (1) the Bank of America, N.A. prime rate, (2) the federal funds rate plus 0.50% and (3) a one-month LIBOR rate adjusted daily plus 1.00%, plus, in each case, an applicable margin. The applicable margin for borrowings is 9.00% for LIBOR loans and 8.00% for Base Rate loans, depending on whether the Base Rate or LIBOR is used. As of December 31, 2015, the applicable rate for borrowings under the Incremental Term Loan was 10.00%. The Incremental Term Loan is payable in equal consecutive quarterly installments equal to 0.25% (1.00% per annum) of the original principal amount of the Incremental Term Loan and will mature in full on June 25, 2021.
During 2015, we repurchased and cancelled $50.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $31.3 million. We recognized gains on extinguishment of debt of $18.1 million, which included accelerated amortization of deferred financing costs of $0.6 million.
For further information on our long-term debt, please read Note 6 to our consolidated financial statements included in Item 8 of this report.
Capital Expenditures
Our business is capital-intensive, requiring significant investment to maintain, upgrade and purchase equipment to meet our customers' needs and industry demand. Our capital requirements have consisted primarily of:
•
growth capital expenditures, which are defined as capital expenditures made to acquire additional equipment and other assets, increase our service lines, expand geographically or advance other strategic initiatives for the purpose of growing our business;
•
maintenance capital expenditures, which are defined as capital expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of components and equipment which are worn or obsolete; and
•
prior to 2015, the purchase of leased drilling rigs.
Total capital expenditures were $205.7 million, $457.6 million and $349.8 million for the years ended December 31, 2015, 2014 and 2013, respectively. During the year ended December 31, 2014, we purchased 45 leased drilling rigs for approximately $158.4 million and paid lease termination costs of approximately $9.7 million, which ended our drilling rig leasing program. For the year ended December 31, 2013, we purchased 23 leased drilling rigs for approximately $140.2 million and paid lease termination costs of approximately $22.4 million. We currently expect to spend approximately $100.0 million in aggregate growth and maintenance capital expenditures in 2016. We may increase, decrease or re-allocate our anticipated capital expenditures during any period based on industry conditions, the availability of capital or other factors, and a significant component of our anticipated capital spending is discretionary. In addition, from time to time we may use cash on hand in excess of our budgeted capital expenditures to repurchase and cancel our outstanding long-term debt or our common stock, subject to approval by our Board of Directors.
Cash Flow
Our cash flow depends in large part on the level of spending by our customers on exploration, development and production activities. Sustained increases or decreases in the price of oil or natural gas could have a material impact on these activities, thus materially affecting our future cash flows. The following is a discussion of our cash flow for the years ended December 31, 2015, 2014 and 2013.
Operating Activities. Cash provided by operating activities was $284.1 million, $265.3 million and $337.1 million for the years ended December 31, 2015, 2014 and 2013, respectively. Changes in working capital items increased (decreased) cash flow provided by operating activities by $163.4 million, ($88.6) million, and $36.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. During the year ended December 31, 2015, the increase in cash provided by operating activities due to changes in working capital items was impacted by the timing of collection of accounts receivable and the decline in overall operational activity. Factors affecting changes in operating cash flows are largely the same as those that affect net income, with the exception of non-cash expenses such as depreciation and amortization, amortization of sale-leaseback gains, amortization of deferred financing costs, gains on early extinguishment of debt, loss on sale of a business, gains or losses on sales of property and equipment, impairments, non-cash compensation, income or losses from equity investees and deferred income taxes.
Investing Activities. Cash used in investing activities was $159.7 million, $367.6 million and $296.8 million for the years ended December 31, 2015, 2014 and 2013, respectively. Capital expenditures are the main component of our investing activities. The majority of our capital expenditures for the years ended December 31, 2015, 2014 and 2013 were related to our investment in PeakeRigs™ and the purchase of certain leased drilling rigs. We purchased 45 leased drilling rigs for approximately $158.4 million during 2014 and 23 leased drilling rigs for approximately $140.2 million during 2013. Cash used in investing activities was partially offset by proceeds from the sale of Hodges of $15.0 million during the second quarter of 2015 and proceeds from asset sales in the amounts of $27.7 million, $88.6 million and $50.6 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Financing Activities. Net cash provided by (used in) financing activities was $5.3 million, $101.6 million and ($39.8) million for the years ended December 31, 2015, 2014 and 2013, respectively. We had borrowings and repayments under our credit facility of $160.1 million and $210.6 million, respectively, during 2015. We had borrowings and repayments under our credit facility of $1.201 billion and $1.556 billion, respectively, during 2014. We had borrowings and repayments under our credit facility of $1.217 billion and $1.230 billion, respectively, during 2013. During 2015, we borrowed $100.0 million under the Incremental Term Loan and received net proceeds of $94.5 million. We also repurchased and cancelled $50.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $31.3 million during 2015. During 2014, we (i) issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022 and used the net proceeds of $493.8 million from the 2022 Notes issuance to make a distribution of approximately $391.0 million to CHK and for general corporate purposes, and (ii) we entered into a $400.0 million seven-year term loan credit agreement and used the net proceeds of $393.9 million to repay and terminate the Old Credit Facility. We paid $0.8 million and $3.6 million in deferred financing costs in 2015 and 2014, respectively. We made term loan repayments of $4.8 million and $2.0 million during 2015 and 2014, respectively. For the years ended December 31, 2014 and 2013 our distributions to CHK were $422.8 million and $29.9 million, respectively.
Results of Operations
Years Ended December 31, 2015, 2014 and 2013
The following table sets forth our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013.
Comparison of Years Ended December 31, 2015 and 2014
Revenues. Revenues and Adjusted Revenues for 2015 decreased $949.6 million and $723.3 million, respectively, compared to 2014, primarily due to decreased utilization and increased pricing pressure. The percentage of our revenues derived from CHK was 70% and 81% for 2015 and 2014, respectively.
(a)
"Adjusted Revenues" is a non-GAAP financial measure we define as revenues before revenues associated with our drilling rig relocation and logistics business and water hauling assets that were sold in the second quarter of 2015, our compression unit manufacturing and geosteering businesses that were distributed to CHK and our crude hauling assets that were sold to a third party as part of the spin-off. For a description of our calculation of Adjusted Revenues and the reasons our management uses this measure to evaluate our business, please read "-How We Evaluate Our Operations" and "-Non-GAAP Financial Measures."
Operating Costs. Operating costs and Adjusted Operating Costs for 2015 decreased $724.5 million and $516.7 million, respectively, compared to 2014. The decrease was primarily due to a decrease in labor-related costs, reduced utilization in our drilling and rental segments and a decrease in product costs in our hydraulic fracturing segment. As a percentage of Adjusted Revenues, Adjusted Operating Costs were 74% and 73% for 2015 and 2014, respectively. The percentage increase was due to declines in utilization.
(a)
“Adjusted Operating Costs” is a non-GAAP financial measure of operating costs that excludes operating costs associated with our rig relocation and logistics business and water hauling assets that were sold in the second quarter of 2015, our compression unit manufacturing and geosteering businesses that were distributed to CHK and our crude hauling assets that were sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense. For a description of our calculation of Adjusted Operating Costs and the reasons why our management uses this measure to evaluate our business, see “-How We Evaluate Our Operations” and “-Non-GAAP Financial Measures.”
Drilling
Drilling revenues for 2015 decreased $338.1 million, or 44%, compared to 2014, due to a 51% decrease in revenue days, which represents the aggregate number of days that each active rig generated revenue. Revenues from non-CHK customers decreased $92.0 million in 2015 as compared to 2014. However, revenues from non-CHK customers increased to 39% of total segment revenues in 2015, compared to 34% in 2014.
Drilling operating costs for 2015 decreased $267.5 million, or 54%, from 2014, primarily as result of a decrease in labor-related costs, lower repairs and maintenance expense and the elimination of rig rent expense. As a percentage of drilling revenues, drilling operating costs were 53% and 64% for 2015 and 2014, respectively. The percentage decrease was due to declines in labor-related costs.
Hydraulic Fracturing
Hydraulic fracturing revenues for 2015 decreased $310.4 million, or 35%, compared to 2014, which was primarily due to a 40% decrease in revenue per stage from 2014 to 2015, partially offset by an 8% increase in completed stages from 2014 to 2015. The decrease in revenue per stage was primarily due to market pricing pressure. Revenues from non-CHK customers increased $75.7 million to 17% of total segment revenues in 2015, compared to 3% in 2014.
Hydraulic fracturing operating costs for 2015 decreased $241.4 million, or 33% compared to 2014, primarily due to a decrease in product costs partially offset by increases in transportation. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs increased from 83% in 2014 to 86% in 2015 primarily due to increases in transportation and increased pricing pressure.
Oilfield Rentals
Oilfield rental revenues for 2015 decreased $76.5 million, or 50%, compared to 2014, due to a decline in utilization and pricing pressure. Revenues from non-CHK customers increased $16.5 million to 59% of total segment revenues in 2015, compared to 19% in 2014.
Oilfield rental operating costs for 2015 decreased $33.7 million, or 33% compared to 2014. The decrease was primarily due to a decrease in repairs and maintenance expense due to lower utilization and a decrease in labor-related costs. As a percentage of oilfield rental revenues, oilfield rental operating costs were 89% and 67% for 2015 and 2014, respectively. The percentage increase was due to one-time labor-related costs in 2015 and significant declines in fleet utilization without corresponding decreases in operating costs.
Former Oilfield Trucking
During the second quarter of 2015, we sold our drilling rig relocation and logistics business and water hauling assets. As of June 30, 2015, there were no remaining assets or operations in this former segment.
Other Operations
(a)
"Adjusted Revenues" and "Adjusted Operating Costs" are non-GAAP financial measures that we define as revenues and operating costs before revenues and operating costs associated with the compression unit manufacturing business distributed to CHK as part of the spin-off. For a description of our calculation of Adjusted Revenues and Adjusted Operating Costs and the reasons why our management uses this measure to evaluate our business, please read "-How We Evaluate Our Operations" and "-Non-GAAP Financial Measures."
Our other operations currently consists of corporate functions. As part of the spin-off, we distributed our compression manufacturing business to CHK, which was historically included in our other operations results.
Depreciation and Amortization. Depreciation and amortization for the years ended December 31, 2015 and 2014 was $295.4 million and $292.9 million, respectively. The increase is primarily due to a change in the estimated useful lives of certain components of drilling rigs and certain drilling rigs. Please read Note 2 to our consolidated financial statements included in Item 8 of this report. As a percentage of revenues, depreciation and amortization expense was 26% and 14% for 2015 and 2014, respectively.
General and Administrative Expenses. General and administrative expenses for the years ended December 31, 2015 and 2014 were $112.1 million and $108.1 million, respectively. The increase was primarily due to an increase in non-cash compensation expenses, which was partially offset by a decrease in CHK transition services costs. We incurred non-cash compensation expenses of $30.2 million and $19.4 million in addition to severance-related costs of $6.4 million and $2.0 million for the years ended December 31, 2015 and 2014, respectively. Included in the non-cash compensation expenses and severance-related costs for 2015 are $2.1 million and $0.6 million, respectively, related to the sale of Hodges. Prior to the spin-off, we were allocated corporate overhead from CHK which covered functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. Under this allocation, we incurred charges of $26.8 million in 2014. During 2015 and 2014, we incurred charges of $8.3 million and $18.0 million, respectively, for services provided by CHK pursuant to the transition services agreement. As of June 30, 2015, SSE terminated all remaining services being provided by CHK. As a percentage of revenues, general and administrative expenses were 10% and 5% for the years ended December 31, 2015 and 2014, respectively.
Loss on Sale of a Business. On June, 14, 2015, we sold Hodges for aggregate consideration of $42.0 million, comprised of $15.0 million in cash and a $27.0 million secured promissory note due June 15, 2020. We recognized a loss of $35.0 million on the sale during 2015.
Losses (Gains) on Sales of Property and Equipment, net. We recorded losses (gains) on sales of property and equipment of approximately $14.7 million and ($6.3) million during the years ended December 31, 2015 and 2014, respectively. During 2015, we sold our water hauling and ancillary equipment not utilized in our business. During 2014, we sold 28 Tier 3 drilling rigs and ancillary drilling equipment and our crude hauling assets, which included 124 fluid handling trucks and 122 trailers.
Impairment of Goodwill. During the fourth quarter of 2015, we recognized an impairment loss of $27.4 million on the goodwill associated with our 2011 Bronco acquisition. See Note 2 of Item 8 for further discussion.
Impairments and Other. During 2015 and 2014, we recognized impairments of $18.6 million and $30.8 million, respectively. During 2015, we recognized impairment charges of $8.7 million, $5.2 million and $2.7 million related to drilling-related services equipment, certain drilling rigs and trucking and fluid disposal equipment, respectively, which we determined were impaired based on the expected future cash flows for these rigs and equipment. During 2014, we recognized impairment charges of $8.4 million related to drilling rigs we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. We paid lease termination costs of $9.7 million during the year ended December 31, 2014. During 2014, we recognized impairments of $11.2 million related to certain drilling rigs and spare equipment that we had identified as held for sale. See Note 5 of Item 8 for further details.
We identified certain other property and equipment during the years ended December 31, 2015 and 2014 that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the related long-lived assets. We recorded impairment charges of $2.0 million and $1.5 million during the years ended December 31, 2015 and 2014, respectively, related to these assets.
Interest Expense. Interest expense for the years ended December 31, 2015 and 2014 was $99.3 million and $79.7 million, respectively, related to borrowings under our senior notes, term loans and credit facility. The increase in interest expense from 2014 to 2015 was primarily due to additional debt issued in conjunction with the spin-off along with the $100.0 million Incremental Term Loan. These debt increases were partially offset by the repurchase and cancellation of $50.0 million in aggregate principal amount of 6.50% Senior Notes due 2022.
Gains on Extinguishment of Debt. During 2015, we repurchased and cancelled $50.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $31.3 million. We recognized gains on extinguishment of debt of $18.1 million, which reflected the accelerated amortization of deferred financing costs of $0.6 million.
Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $7.9 million and $6.1 million for the years ended December 31, 2015 and 2014, respectively, which was a result of our 49% membership interest in Maalt Specialized Bulk, L.L.C. ("Maalt"). We recorded non-cash impairment charges of $8.8 million and $4.5 million for the years ended December 31, 2015 and 2014, respectively, which resulted from an excess of carrying value over the estimated fair value for this investment.
Other Income. Other income for the years ended December 31, 2015 and 2014 was $3.1 million and $0.7 million, respectively.
Income Tax Benefit. We recorded an income tax benefit of $92.6 million and $2.2 million for the years ended December 31, 2015 and 2014, respectively. The $90.4 million increase in income tax benefit recorded for 2015 was primarily the result of an increase in our pre-tax loss from $10.2 million in 2014 to $314.0 million in 2015. Our effective income tax rate for 2015 and 2014 was 29% and 22%, respectively. The increase in our effective tax rate from 2014 to 2015 was primarily the result of permanent differences having a greater impact on our effective income tax rate due to lower pre-tax loss base in 2014 compared to 2015.
Comparison of Years Ended December 31, 2014 and 2013
Revenues. For 2014 and 2013, revenues were $2.081 billion and $2.188 billion, respectively. The $107.3 million decrease from 2013 to 2014 was primarily due was due to the distribution to CHK of our compression unit manufacturing and geosteering businesses and the sale of our crude hauling assets to a third party as part of the spin-off. Our Revenues and Adjusted Revenues for 2014 and 2013 are detailed below:
(a)
"Adjusted Revenues" is a non-GAAP financial measure we define as revenues before revenues associated with our drilling rig relocation and logistics business and water hauling assets that were sold in the second quarter of 2015, our compression unit manufacturing and geosteering businesses that were distributed to CHK and our crude hauling assets that were sold to a third party as part of the spin-off. For a description of our calculation of Adjusted Revenues and the reasons our management uses this measure to evaluate our business, please read "-How We Evaluate Our Operations" and "-Non-GAAP Financial Measures."
Operating Costs. Operating costs decreased $137.4 million and Adjusted Operating Costs increased $13.2 million in 2014 compared to 2013. The decline in operating costs was due to the distribution to CHK of our compression unit manufacturing and geosteering businesses and the sale of our crude hauling assets to a third party as part of the spin-off. As a percentage of Adjusted Revenues, Adjusted Operating Costs were 73% and 73% for the 2014 and 2013, respectively.
(a)
"Adjusted Operating Costs" is a non-GAAP financial measure that we define as operating costs before operating costs associated with our drilling rig relocation and logistics business and water hauling assets that were sold in the second quarter of 2015, our compression unit manufacturing and geosteering businesses that were distributed to CHK and our crude hauling assets that were sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense. For a description of our calculation of Adjusted Operating Costs and the reasons why our management uses this measure to evaluate our business, please read "-How We Evaluate Our Operations" and "-Non-GAAP Financial Measures."
Drilling
Drilling revenues for 2014 increased $33.7 million, or 5%, compared to 2013, primarily due to an increase in revenue days of 2,155 days, or 8%. Revenues from non-CHK customers increased $113.6 million to 34% of total segment revenues in 2014, compared to 20% in 2013.
Drilling operating costs for 2014 decreased $44.2 million, or 8%, compared to 2013, primarily as result of a $58.0 million reduction in rig rent expense due to the repurchase of 45 drilling rigs during 2014. As a percentage of drilling revenues, drilling operating costs were 64% and 73% for 2014 and 2013, respectively. As a percentage of drilling revenues, rig rent expense was 2% and 10% for 2014 and 2013, respectively.
Hydraulic Fracturing
Hydraulic fracturing revenues for 2014 decreased $11.9 million, or 1%, compared to 2013. This decrease was due to a 15% decrease in revenue per stage from 2013 to 2014, partially offset by a 16% increase in completed stages from 2013 to 2014. The decrease in revenue per stage was primarily due to market pricing pressure. Revenues from non-CHK customers increased $22.0 million to 3% of total segment revenues in 2014.
Hydraulic fracturing operating costs for 2014 decreased $4.5 million compared to 2013, primarily due to a decrease in product costs, partially offset by an increase in repairs and maintenance expenses. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs increased from 82% in 2013 to 83% in 2014.
Oilfield Rentals
Oilfield rental revenues for 2014 decreased $7.1 million, or 4%, compared to 2013. The decrease was primarily due to market pricing pressure for certain of our equipment. Revenues from non-CHK customers increased $21.0 million to 19% of total segment revenues in 2014, compared to 5% in 2013.
Oilfield rental operating costs for 2014 increased $0.3 million, or less than 1%, compared to 2013. As a percentage of oilfield rental revenues, oilfield rental operating costs were 67% and 63% for 2014 and 2013, respectively. The increase in
oilfield rental operating costs as a percentage of oilfield rental revenues was primarily attributable to market pricing pressure for certain services, which compressed margins, and an increase in labor-related costs related to the expansion of our business development organization. As a percentage of oilfield rental revenues, labor-related costs were 32% and 29% in 2014 and 2013, respectively.
Former Oilfield Trucking
Oilfield trucking revenues for 2014 decreased $53.9 million or 22%, compared to 2013. The decrease was primarily due to the sale of our crude hauling assets to a third party in the second quarter of 2014. Revenues from non-CHK customers increased $26.9 million to 32% of total segment revenues in 2014, compared to 14% in 2013.
Oilfield trucking operating costs for 2014 decreased $27.6 million, or 13%, compared to 2013. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 95% and 85% for 2014 and 2013, respectively. The increase in operating costs as a percentage of revenue was primarily attributable to an increase in labor-related costs due to higher wages in a competitive market for trucking labor, and secondarily, a decrease in utilization of our assets which resulted in fixed costs being spread over a smaller revenue base. As a percentage of oilfield trucking revenues, labor-related costs were 46% and 42% for 2014 and 2013, respectively.
During the second quarter of 2014, we sold our crude hauling assets to a third party. The operating results related to the crude hauling assets were historically included in our oilfield trucking segment and the associated revenues and operating costs are detailed below:
Other Operations
Our other operations currently consists of corporate functions. As part of the spin-off, we distributed our compression unit manufacturing business to CHK, which was historically included in our other operations results. For 2014, revenues from our other operations decreased $68.1 million compared to 2013, which was primarily attributable to the distribution of our compression unit manufacturing business to CHK.
For 2014, operating costs for our other operations decreased $61.3 million compared to 2013, which was primarily attributable to the distribution of our compression unit manufacturing business to CHK. This business was historically included in our other operations results and the associated revenues and operating costs are detailed below:
Depreciation and Amortization. Depreciation and amortization for the years ended December 31, 2014 and 2013 was $292.9 million and $289.6 million, respectively. The increase reflects the additional investments in our asset base as a result of capital expenditures, primarily for new hydraulic fracturing equipment and PeakeRigs™. As a percentage of revenues, depreciation and amortization expense was 14% and 13% for 2014 and 2013, respectively.
General and Administrative Expenses. General and administrative expenses for the years ended December 31, 2014 and 2013 were $108.1 million and $80.4 million, respectively. The increase was primarily due to an increase in labor-related costs and secondarily, the incremental costs of being a stand-alone public entity and implementing an enterprise resource planning system. Prior to the spin-off, we were allocated corporate overhead from CHK which covered functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. These charges from CHK were $26.8 million and $55.5 million for 2014 and 2013, respectively. Following the spin-off, we incurred charges of $18.0 million for services provided to us by CHK pursuant to a transition services agreement. As a percentage of revenues, general and administrative expenses were 5% and 4% for 2014 and 2013, respectively.
Gains on Sales of Property and Equipment. During the year ended December 31, 2014, we sold 28 drilling rigs and ancillary equipment not utilized in our business as well as our crude hauling fleet, which included 124 fluid handling trucks and 122 trailers. During the year ended December 31, 2013, we sold 14 drilling rigs and ancillary equipment not utilized in our business. We recorded net gains on sales of property and equipment of approximately $6.3 million and $2.6 million related to these asset sales during the years ended December 31, 2014 and 2013, respectively.
Impairments and Other. During the years ended December 31, 2014 and 2013, we recognized $11.2 million and $23.6 million, respectively, of impairment charges for certain drilling rigs and spare equipment that we identified for sale as part of our broader strategy to divest non-essential drilling rigs. We also identified certain drilling rigs during the years ended December 31, 2014 and 2013 that we deemed to be impaired based on our assessment of future demand, and the suitability of the identified rigs in light of this demand. We recorded impairment charges of $8.4 million and $25.4 million during the years ended December 31, 2014 and 2013, respectively, related to these drilling rigs.
During the year ended December 31, 2014, we purchased 45 of our drilling rigs for approximately $158.4 million and paid lease termination costs of $9.7 million. During the year ended December 31, 2013, we purchased 23 of our drilling rigs for approximately $140.2 million and paid lease termination costs of $22.4 million.
We identified certain other property and equipment during the years ended December 31, 2014 and 2013 that we deemed to be impaired based on our assessment of the fair value of such assets. We recorded impairment charges of $1.5 million and $3.4 million during the years ended December 31, 2014 and 2013, respectively, related to these assets.
Interest Expense. Interest expense for the years ended December 31, 2014 and 2013 was $79.7 million and $56.8 million, respectively. The increase in interest expense from 2013 to 2014 was due to the additional debt issued in conjunction with the spin-off.
Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $6.1 million and $1.0 million for the years ended December 31, 2014 and 2013, respectively, which was a result of our investments in Maalt Specialized Bulk, L.L.C. ("Maalt") and Big Star Crude Co., L.L.C. ("Big Star"). We own 49% of the membership interest in Maalt. In the second quarter of 2014, we recorded a non-cash impairment charge of $4.5 million, which resulted from an excess of carrying value over the estimated fair value for this investment. During the year ended December 31, 2013, we sold our membership interest in Big Star and recorded a loss on sale of $1.8 million.
Other Income. Other income for the years ended December 31, 2014 and 2013 was $0.7 million and $1.8 million, respectively.
Income Tax Benefit. We recorded income tax benefit of $2.2 million and $7.8 million for the years ended December 31, 2014 and 2013, respectively. The $5.6 million decrease in income tax benefit recorded for 2014 was primarily the result of a decrease in our pre-tax loss from $27.6 million in 2013 to $10.2 million in 2014. Our effective income tax rate for 2014 and 2013 was 22% and 28%, respectively. The decrease in our effective tax rate from 2013 to 2014 was primarily the result of permanent differences having a greater impact on our effective income tax rate due to lower pre-tax loss base in 2014 compared to 2013.
Contractual Commitments and Obligations
In the normal course of business, we enter into various contractual obligations that impact, or could impact, our liquidity. The following table summarizes our material obligations as of December 31, 2015:
(a)
Please read Note 2 to our consolidated financial statements included in Item 8 of this report.
(b)
Please read Note 6 to our consolidated financial statements included in Item 8 of this report.
(c)
Amount includes contractual interest payments on the 2019 Senior Notes, 2022 Senior Notes and Term Loans.
(d)
Consists of unconditional obligations to purchase equipment. Please read Note 8 to our consolidated financial statements included in Item 8 of this report.
(e)
Consists of rail car and other operating leases. Amounts disclosed assume no exercise of options to renew or extend the leases. Please read Note 8 to our consolidated financial statements included in Item 8 of this report.
Off-Balance Sheet Arrangements
As of December 31, 2015, we were party to five lease agreements with various third parties to utilize 725 lease rail cars for initial terms of five to seven years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreement. We account for these leases as operating leases.
As of December 31, 2015, we were also party to various lease agreements for other property and equipment with varying terms. We account for these leases as operating leases.
Aggregate undiscounted minimum future lease payments as of December 31, 2015 under our rail car and other operating leases are presented below:
Other Commitments
Much of the equipment we purchase requires long production lead times. As a result, we usually have outstanding orders and commitments for such equipment. As of December 31, 2015, we had $69.0 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2016.
Critical Accounting Policies
Our consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States of America, which require us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reported periods.
Property and Equipment
Property and equipment are carried at cost less accumulated depreciation. Depreciation is calculated using the straight-line method, based on estimates, assumptions and judgments relative to the assets' estimated useful lives and salvage values. These estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Upon the disposition of an asset, we eliminate the cost and related accumulated depreciation and include any resulting gain or loss in the consolidated statements of operations as (gains) losses on the sale of property and equipment. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred.
Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using a weighted average interest rate based on our outstanding borrowings until the underlying assets are placed into service. The capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets.
Impairment of Long-Lived Assets
We review our long-lived assets, such as property and equipment, whenever, in management's judgment, events or changes in circumstances indicate the carrying amount of the assets may not be fully recoverable. Factors that might indicate a potential impairment include a significant decrease in the market value of the long-lived asset, a significant change in the long-lived asset's physical condition, a change in industry conditions or a reduction in cash flows associated with the use of the long-lived asset. If these or other factors indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through analysis of the future undiscounted cash flows of the asset. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair market value of the asset. We measure the fair value of the asset using market prices or, in the absence of market prices, based on an estimate of discounted cash flows.
During 2015, other than in the second quarter of 2015 when oil prices improved and averaged $57.85 per barrel, the sustained decline in commodity prices since mid-2014 significantly reduced the level of onshore United States drilling and completions activity and, consequently, the demand for our services. As of December 31, 2015, NYMEX WTI oil spot prices had declined significantly to their lowest levels since 2003. Due to the prolonged period of depressed oil and natural gas prices and the further deterioration of industry conditions in the fourth quarter of 2015, management deemed it necessary to assess the recoverability of the long-lived asset groups for drilling, hydraulic fracturing and oilfield rentals. We performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of the long-lived assets within these segments. With respect to these assets, future cash flows were estimated over the expected remaining useful life of the assets and on an undiscounted basis. Based on the analysis, we determined that, other than for certain Tier 2 drilling rigs, estimated cash flows exceeded the carrying value of the long-lived assets, and no impairment was indicated as of December 31, 2015. The estimated cash flows for the drilling and hydraulic fracturing asset groups include the backlog of contract revenues, which was approximately $355.8 million and $282.7 million, respectively, as of December 31, 2015. Assets not under contracts will be subject to pricing in the spot market. Utilization and rates for assets in the spot market were estimated based upon our management's experience in prior downturns. Also, the estimated cash flows are based on the assumption that activity levels in drilling, hydraulic fracturing and oilfield rentals will begin to recover in the first half of 2017 in response to improved oil and natural gas prices. While management believes its assumptions are reasonable, actual events may vary materially from assumptions. The timing and the extent to which oil and natural gas prices will recover is highly uncertain. Potential events that could affect our assumptions include factors such as:
•
market supply and demand for oil and natural gas,
•
domestic and international military, political, economic and weather conditions,
•
the desire and ability of the Organization of Petroleum Exporting Countries, commonly known as OPEC, to set and maintain production and price targets that support oil and natural gas prices,
•
legal and other limitations or restrictions on exportation and/or importation of oil and natural gas,
•
technical advances affecting energy consumption and production,
•
the price and availability of alternative fuels,
•
the cost of exploring for, developing, producing and delivering oil and natural gas, and
•
regulations regarding the exploration, development, production and delivery of oil and natural gas.
All of these factors, as well as others discussed in the "Risk Factors" section of this report, may cause actual results to differ and vary beyond our control. If the current lower oil and natural gas commodity price and capital spending environment were to last into 2017 and beyond, our actual cash flows would likely be less than the estimated cash flows used in our assessment and could result in impairment charges in the future, which could be material. See Note 5 for discussion of impairments recognized.
Goodwill, Intangible Assets and Amortization
Goodwill represents the cost in excess of fair value of the net assets of businesses acquired. Goodwill is not amortized. Intangible assets with finite lives are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line basis over an asset's estimated useful life.
We review goodwill for impairment annually on October 1 or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit exceeds its fair value. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. We have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then there is no need to perform any further testing. However, if we conclude otherwise, accounting guidance requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value. We have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test.
When estimating fair values of a reporting unit for our goodwill impairment test, we use the income approach. The income approach provides an estimated fair value based on the reporting unit's anticipated cash flows that are discounted using a weighted average cost of capital rate. Estimated cash flows are primarily based on projected revenues, operating expenses and capital expenditures and are discounted using comparable industry average rates for weighted average cost of capital.
In response to further deterioration of industry conditions in the fourth quarter of 2015, the Company determined that there were indications of impairment present. During the fourth quarter of 2015, the Company completed its assessment and recognized an impairment loss of $27.4 million on the goodwill associated with Bronco acquisition.
Revenue Recognition
We recognize revenue when services are performed, collection of receivables is reasonably assured, persuasive evidence of an arrangement exists and the price is fixed or determinable.
Drilling. We earn revenues by drilling oil and natural gas wells for our customers under daywork contracts. We recognize revenue on daywork contracts for the days completed based on the day rate each contract specifies. Payments received and costs incurred for mobilization services are recognized as earned over the days of mobilization. We also recognize revenue for contract termination fees paid by our customers. Under certain of our contracts, we have agreed to allow customers to pay the termination cost over the life of the contract in lieu of a lump sum, and we refer to a rig in this circumstance as "idle but contracted" or "IBC". IBC payments are structured to preserve our anticipated operating margins for the affected rigs through the end of the contract terms and are recognized as revenue over the life of the contract.
Hydraulic Fracturing. We recognize revenue upon the completion of each fracturing stage. We typically complete one or more fracturing stages per day per active crew during the course of a job. A stage is considered complete when the customer requests or the job design dictates that pumping discontinue for that stage. Invoices typically include a lump sum equipment charge determined by the rate per stage each contract specifies and product charges for sand, chemicals and other products actually consumed during the course of providing our services.
Oilfield Rentals. We rent many types of oilfield equipment, including drill pipe, drill collars, tubing, blowout preventers, frac tanks, mud tanks and environmental containment. We also provide air drilling, flowback services and services associated with the transfer of water to the wellsite for well completions. We price our rentals and services by the day or hour based on the type of equipment rented and the services performed and recognize revenue ratably over the term of the rental.
Former Oilfield Trucking. During the second quarter of 2015, we sold our drilling rig relocation and logistics business and water hauling assets. As of June 30, 2015, there were no remaining assets or operations in this former segment.
Income Taxes
Through the effective date of the spin-off, our operations were included in the consolidated federal income tax return and other state returns for CHK. The income tax provision for the period before the spin-off has been prepared on a separate return basis for us and all of our subsidiaries. Accordingly, we have recognized deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases for all our subsidiaries as if each entity were a corporation, regardless of its actual characterization for U.S. federal income tax purposes. Effective with the spin-off, we entered into a tax sharing agreement with CHK which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off, with respect to the payment of taxes, filing of tax returns, reimbursement of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off and other matters regarding taxes. Following the spin-off, we are not entitled to federal income tax net operating loss ("NOL") carryforwards that were generated prior to the spin-off and that have historically been reflected in our net deferred income tax liabilities on our consolidated balance sheet.
A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. We had no income tax valuation allowance as of December 31, 2015 and 2014.
The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions as of December 31, 2015 and 2014.
New Accounting Pronouncements
In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2015-17, "Income Taxes," which simplifies the presentation of deferred income taxes by requiring deferred tax liabilities and assets be classified as noncurrent in the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.
In July 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory,” which changes inventory measured using any method other than LIFO or the retail inventory method (for example, inventory measured using first-in, first-out (FIFO) or average cost) at the lower of cost and net realizable value. ASU 2015-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.
In August 2014, the FASB issued ASU No 2014-15, "Presentation of Financial Statements - Going Concern," which requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). ASU 2014-15 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605)” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; the FASB also provided for early adoption for annual reporting periods beginning after December 15, 2016. We are currently evaluating what impact this standard will have on our consolidated financial statement.
Inflation
Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2015, 2014 and 2013. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and we tend to experience inflationary pressure on the cost of energy services and equipment as increasing oil and natural gas prices increase activity in our areas of operations.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Historically, we have provided a significant percentage of our oilfield services to CHK and its working interest partners. For the years ended December 31, 2015, 2014 and 2013, CHK accounted for approximately 70%, 81% and 90% of our revenues, respectively. The decline in commodity prices since mid-2014 has had an adverse effect on CHK's and our other customers' capital spending, which has adversely impacted our cash flows and financial position. The extent and length of the current down cycle is uncertain. If it is prolonged or worsens, it could have a further adverse effect on our customers' capital spending. This would likely have a material adverse impact on our cash flows and financial position and could adversely affect our ability to comply with the financial covenant under our credit facility and limit our ability to fund our planned capital expenditures.
Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our credit facility and term loans. We have borrowings outstanding under our term loans and may in the future borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Our primary exposure to interest rate risk results from outstanding borrowings under our credit facility and term loans.
The following table provides information about our debt instruments that are sensitive to changes in interest rates. The table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at December 31, 2015.
Our fuel costs, which consist primarily of diesel fuel used by our various trucks and other equipment, can expose us to commodity price risk and, as our hydraulic fracturing operations grow, we will face increased risks associated with the prices of materials used in hydraulic fracturing, such as sand and chemicals. The prices for fuel and these materials can be volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages.
Historically, we have not used derivative financial instruments to manage our exposure to these risks.
Item 8.
Item 8.
Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Seventy Seven Energy Inc.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Seventy Seven Energy Inc. and its subsidiaries (the "Company") at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 2 to the consolidated financial statements, the Company is actively exploring and evaluating strategic alternatives to reduce the level of the Company's long-term debt and lower its future cash interest obligations.
As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it presents deferred financing costs in 2015.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
February 17, 2016
SEVENTY SEVEN ENERGY INC.
Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements.
SEVENTY SEVEN ENERGY INC.
Consolidated Statements of Operations
The accompanying notes are an integral part of these consolidated financial statements.
SEVENTY SEVEN ENERGY INC.
Consolidated Statements of Changes in Equity
The accompanying notes are an integral part of these consolidated financial statements.
SEVENTY SEVEN ENERGY INC.
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these consolidated financial statements.
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Spin-off and Basis of Presentation
Spin-Off
On June 9, 2014, Chesapeake Energy Corporation ("CHK") announced that its board of directors approved the spin-off of its oilfield services division through the pro rata distribution of 100% of the shares of common stock of Seventy Seven Energy Inc. ("SSE," "we," "us," "our," "Company," or "ours") to CHK's shareholders of record as of the close of business on June 19, 2014, the record date. On June 30, 2014, each CHK shareholder received one share of SSE common stock for every fourteen shares of CHK common stock held by such shareholder on the record date, and SSE became an independent, publicly traded company as a result of the distribution. The transactions in which SSE became an independent, publicly traded company, including the distribution, are referred to collectively as the "spin-off". Prior to the spin-off, we conducted our business as CHK Oilfield Operating, L.L.C. ("COO"), a wholly owned subsidiary of CHK. Following the spin-off, CHK retained no ownership interest in SSE, and each company has separate public ownership, boards of directors and management. A registration statement on Form 10, as amended through the time of its effectiveness, describing the spin-off was filed by SSE with the U.S. Securities and Exchange Commission ("SEC") and was declared effective on June 17, 2014. On July 1, 2014, SSE stock began trading the "regular-way" on the New York Stock Exchange under the ticker symbol of "SSE". See Note 14 for further discussion of agreements entered into as part of the spin-off, including a master separation agreement, a transition services agreement, an employee matters agreement and a tax sharing agreement, among others. As part of the spin-off, we completed the following transactions, among others, which we refer to as the "Transactions":
•
we entered into a new $275.0 million senior secured revolving credit facility (the "credit facility") and a $400.0 million secured term loan (the "Term Loan"). We used the proceeds from borrowings under these new facilities to repay in full and terminate our $500.0 million senior secured revolving credit facility (the "Old Credit Facility").
•
we issued new 6.50% senior unsecured notes due 2022 (the "2022 Notes") and used the net proceeds of approximately $493.8 million to make a cash distribution of approximately $391.0 million to CHK, to repay a portion of outstanding indebtedness under the credit facility and for general corporate purposes.
•
we distributed our compression unit manufacturing and geosteering businesses to CHK.
•
we sold our crude hauling assets to a third party and used a portion of the net proceeds received to make a $30.9 million cash distribution to CHK.
•
CHK transferred to us buildings and real estate used in our business, including property and equipment, at cost of approximately $212.5 million and accumulated depreciation of $22.2 million as of the date of the spin-off.
•
COO transferred all of its existing assets, operations and liabilities, including our 6.625% senior unsecured notes due 2019 (the "2019 Notes"), to Seventy Seven Operating LLC ("SSO"). SSO is an Oklahoma limited liability company, our direct wholly-owned subsidiary and, after giving effect to the Transactions, the owner of all our operating subsidiaries.
•
COO was renamed SSE and converted from a limited liability company to a corporation.
Basis of Presentation
The accompanying consolidated financial statements and related notes include the accounts of SSE and its subsidiaries, all of which are 100% owned. SSE's accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America ("GAAP"). All significant intercompany accounts and transactions within SSE have been eliminated.
Seventy Seven Finance Inc. ("SSF") is a 100% owned finance subsidiary of SSE that was incorporated for the purpose of facilitating the offering of SSE's 2019 Notes (see Note 6). SSF does not have any operations or revenues.
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2. Significant Accounting Policies
Accounting Estimates
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of revenues and expenses during the reporting periods. Although management believes these estimates are reasonable, actual results could differ from those estimates. Areas where critical accounting estimates are made by management include:
•
estimated useful lives of assets, which impacts depreciation and amortization of property and equipment;
•
impairment of long-lived assets, goodwill and intangibles;
•
income taxes;
•
accruals related to revenue, expenses, capital costs and contingencies; and
•
cost allocations as described in Note 14.
Risks and Uncertainties
We operate in a highly cyclical industry. The main factor influencing demand for oilfield services is the level of drilling and completions activity by E&P companies, which in turn depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. Demand for oil and natural gas is cyclical and is subject to large and rapid fluctuations. When oil and natural gas price increases occur, producers increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. The increased capital expenditures also ultimately result in greater production, which historically has resulted in increased supplies and reduced prices that, in turn, tends to reduce demand for oilfield services. For these reasons, our results of operations may fluctuate from quarter-to-quarter and from year-to-year.
The sustained decline in commodity prices since mid-2014 has dramatically reduced the level of onshore United States drilling and completions activity and, consequently, the demand for our services. As of December 31, 2015, NYMEX WTI oil spot prices had declined to their lowest levels since 2003 and NYMEX natural gas spot prices had fallen from multi-year highs reached in early 2014. The extent and length of the current down cycle continues to be uncertain and is dependent on a number of economic, geopolitical and monetary policy factors that are outside our control. Until there is a sustained recovery in commodity prices, we expect that reduced equipment utilization levels and pricing pressure across each of our operating segments will persist. If drilling and completions activity remains at depressed levels or worsens, it would likely have a material adverse impact on our business, financial condition, cash flows and results of operations.
We have retained restructuring advisors and are actively exploring and evaluating various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including debt repurchases, exchanges of existing debt securities for new debt securities and exchanges or conversions of existing debt securities for new equity securities, among other options. The timing and outcome of these efforts is highly uncertain, and one or more of these alternatives could potentially be consummated, without the consent of any one or more of our current security holders, through voluntary bankruptcy proceedings. Although we believe that we will have adequate liquidity over the next twelve months to operate our business and to meet our cash requirements, based on current market conditions, we believe that a reduction in our long-term debt is needed to improve our financial position and flexibility and to better position us to take advantage of the growth opportunities that are likely to result from the current industry downturn.
In addition, on January 18, 2016, we received notice that we are not in compliance with the continued listing standards of the NYSE because the current trading price for our common stock is below the minimum listing requirements. We intend to take actions to meet the compliance standards for continued listing on the NYSE. However, we cannot guarantee that we will be able to meet the necessary requirements for continued listing, and, therefore, we cannot guarantee that our common stock will remain listed for trading on the NYSE.
Historically, we have provided a significant percentage of our oilfield services to CHK. For the years ended December 31, 2015, 2014 and 2013, CHK accounted for approximately 70%, 81% and 90%, respectively, of our revenues. As of December 31, 2015 and 2014, CHK accounted for approximately 65% and 77%, respectively, of our accounts receivable. If CHK ceases to engage us on terms that are attractive to us during any future period, our business, financial condition, cash flows and results of operations would be materially adversely affected during such period.
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Accounts Receivable
Trade accounts receivable are recorded at the invoice amount and do not bear interest. The majority of our receivables, 65% and 77% at December 31, 2015 and 2014, respectively, are with CHK and its subsidiaries. The allowance for doubtful accounts represents our best estimate for losses that may occur resulting from disputed amounts with our customers and their inability to pay amounts owed. We determine the allowance based on historical write-off experience and information about specific customers. During the years ended December 31, 2015, 2014 and 2013, we recognized $1.4 million, $2.9 million and $0.4 million, respectively, of bad debt expense related to potentially uncollectible receivables. We also recognized reductions to our allowance of $0.5 million, $0.1 million and $0.4 million as we wrote off specific receivables against our allowance for the years ended December 31, 2015, 2014 and 2013, respectively.
Inventory
We value inventory at the lower of cost or market using the average cost method. Average cost is derived from third-party invoices and production cost. Production cost includes material, labor and manufacturing overhead. Inventory primarily consists of proppants and chemicals used in our hydraulic fracturing operations.
Property and Equipment
Property and equipment are carried at cost less accumulated depreciation. Depreciation of assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Upon the disposition of an asset, we eliminate the cost and related accumulated depreciation and include any resulting gain or loss in operating expenses in the consolidated statements of operations. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred.
A summary of our property and equipment amounts and useful lives is as follows:
Depreciation is calculated using the straight-line method based on the assets' estimated useful lives and salvage values. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.
We review the estimated useful lives of our property and equipment on an ongoing basis. Based on this review in 2015, we concluded that the estimated useful lives of certain drilling rig components and certain drilling rigs were shorter than the estimated useful lives used for depreciation in our consolidated financial statements. We reflected this useful life change as a change in estimate, effective January 1, 2015, which increased depreciation expense by $13.7 million, increased net loss by $9.7 million and increased our basic and diluted loss per share by $0.19 for the year ended December 31, 2015. Effective July 1, 2014, we concluded that the estimated useful lives of certain of our Tier 2 and Tier 3 drilling rigs were shorter than the
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
estimated useful lives used for depreciation. This change in estimate increased depreciation expense by $3.9 million, increased net loss by $3.0 million and increased basic and diluted loss per share by $0.08 for the year ended December 31, 2014.
Depreciation expense on property and equipment for the years ended December 31, 2015, 2014 and 2013 was $295.1 million, $290.9 million and $285.6 million, respectively. Included in property and equipment are $77.7 million and $139.3 million at December 31, 2015 and 2014, respectively, of assets that are being constructed or have not been placed into service, and therefore are not subject to depreciation.
Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using a weighted average interest rate based on our outstanding borrowings until the underlying assets are placed into service. Capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets. During the years ended December 31, 2015, 2014 and 2013, we capitalized interest of approximately $2.3 million, $2.1 million and $1.1 million, respectively.
Impairment of Long-Lived Assets
We review our long-lived assets, such as property and equipment, whenever, in management's judgment, events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. Factors that might indicate a potential impairment include a significant decrease in the market value of the long-lived asset, a significant change in the long-lived asset's physical condition, a change in industry conditions or a reduction in cash flows associated with the use of the long-lived asset. If these or other factors indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through analysis of the future undiscounted cash flows of the asset. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair value of the asset. We measure the fair value of the asset using market prices or, in the absence of market prices, based on an estimate of discounted cash flows.
Investments
Investments in securities are accounted for under the equity method in circumstances where we have the ability to exercise significant influence over the operating and investing policies of the investee but do not have control. Under the equity method, we recognize our share of the investee's earnings in our consolidated statements of operations. We consolidate all subsidiaries in which we hold a controlling interest.
We evaluate our investments for impairment and recognize a charge to earnings when any identified impairment is determined to be other-than-temporary. See Note 11 for further discussion of investments.
Goodwill, Intangible Assets and Amortization
Goodwill represents the cost in excess of fair value of the net assets of businesses acquired. In 2011, we recorded goodwill in the amount of $27.4 million related to our acquisition of Bronco Drilling Company, Inc. ("Bronco"). This goodwill was assigned to our drilling segment. Goodwill is not amortized. Intangible assets with finite lives are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line basis over an asset's estimated useful life.
We review goodwill for impairment annually on October 1 or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit exceeds its fair value. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. Under GAAP, we have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, there is no need to perform any further testing. However, if we conclude otherwise, accounting guidance requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the goodwill over its implied fair value.
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
When estimating fair values of a reporting unit for our goodwill impairment test, we use the income approach. The income approach provides an estimated fair value based on the reporting unit's anticipated cash flows that are discounted using a weighted average cost of capital rate. Estimated cash flows are primarily based on projected revenues, operating expenses and capital expenditures and are discounted using comparable industry average rates for weighted average cost of capital. For purposes of performing the impairment tests for goodwill, all of our goodwill related to our drilling reporting unit. We performed the two-step process for testing goodwill for impairment on October 1, 2015.
Due to the further deterioration of industry conditions in the fourth quarter of 2015, including the further decline in oil and natural gas prices, the Company determined that there was an indication of impairment present based on the results of the first step of the goodwill impairment test. During the fourth quarter of 2015, we completed our assessment and recognized an impairment loss of $27.4 million on the goodwill associated with the Bronco acquisition.
Deferred Financing Costs
Legal fees and other costs incurred in obtaining financing are amortized over the term of the related debt using a method that approximates the effective interest method. We had gross capitalized costs of $37.3 million and $31.0 million, net of accumulated amortization of $12.4 million and $7.1 million, at December 31, 2015 and 2014, respectively. In 2015, we capitalized costs of $6.3 million associated with the issuance of a Term Loan due 2021. Amortization expense related to deferred financing costs was $4.6 million, $6.1 million and $2.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, and is included in interest expense in the consolidated statements of operations.
In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. This standard requires retrospective application. This ASU is effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted and we elected to adopt ASU 2015-03 effective December 31, 2015. This change in accounting principle is preferable since it allows debt issuance costs and debt issuance discounts to be presented similarly in the consolidated balance sheets as a reduction to the face amount of our debt balances. A retrospective change to the December 31, 2014 consolidated balance sheet as previously presented is required pursuant to ASU 2015-03. The retrospective adjustment to the December 31, 2014 consolidated balance sheet is shown below.
(a)
The deferred financing costs, as adjusted, were incurred in association with the credit facility (See Note 6).
Accounts Payable
Included in accounts payable at December 31, 2014 are liabilities of $4.5 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts, considering the legal right of offset.
Revenue Recognition
We recognize revenue when services are performed, collection of receivables is reasonably assured, persuasive evidence of an arrangement exists and the price is fixed or determinable.
Drilling. We earn revenues by drilling oil and natural gas wells for our customers under daywork contracts. We recognize revenue on daywork contracts for the days completed based on the day rate each contract specifies. Payments received and costs incurred for mobilization services are recognized as earned over the days of mobilization. We also recognize revenue for contract termination fees paid by our customers. Under certain of our contracts, we have agreed to allow customers to pay the termination cost over the life of the contract in lieu of a lump sum, and we refer to a rig in this circumstance as "idle but contracted" or "IBC". IBC payments are structured to preserve our anticipated operating margins for the affected rigs through the end of the contract terms and are recognized as revenue over the life of the contract.
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Hydraulic Fracturing. We recognize revenue upon the completion of each fracturing stage. We typically complete one or more fracturing stages per day per active crew during the course of a job. A stage is considered complete when the customer requests or the job design dictates that pumping discontinue for that stage. Invoices typically include a lump sum equipment charge determined by the rate per stage each contract specifies and product charges for sand, chemicals and other products actually consumed during the course of providing our services.
Oilfield Rentals. We rent many types of oilfield equipment including drill pipe, drill collars, tubing, blowout preventers, frac tanks, mud tanks and environmental containment. We also provide air drilling, flowback services and services associated with the transfer of water to the wellsite for well completions. We price our rentals and services by the day or hour based on the type of equipment rented and the services performed and recognize revenue ratably over the term of the rental.
Former Oilfield Trucking. Oilfield trucking provided rig relocation and logistics services as well as fluid handling services. Our trucks moved drilling rigs, crude oil, and other fluids and construction materials to and from the wellsite and also transported produced water from the wellsite. We priced these services by the hour and volume and recognized revenue as services were performed. As part of the spin-off, we sold our crude hauling business to a third party. During 2015, we sold our drilling rig relocation and logistics business and water hauling assets. As of June 30, 2015, there were no remaining assets or operations in this former segment.
Other Operations. We designed, engineered and fabricated natural gas compression packages, accessories and related equipment that we sold to CHK and other customers. We priced our compression units based on certain specifications such as horsepower, stages and additional options. We recognized revenue upon completion and transfer of ownership of the natural gas compression equipment. As part of the spin-off, we distributed our compression unit manufacturing business to CHK.
Litigation Accruals
We estimate our accruals related to litigation based on the facts and circumstances specific to the litigation and our past experience with similar claims. We estimate our liability related to pending litigation when we believe the amount or a range of the loss can be reasonably estimated. We record our best estimate of a loss when the loss is considered probable. When a loss is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to a lawsuit or claim. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates accordingly.
Environmental Costs
Our operations involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and regulated substances. These operations are subject to various federal, state and local laws and regulations intended to protect the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. There were no amounts capitalized as of December 31, 2015 and 2014. We record liabilities on an undiscounted basis when remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated.
Leases
We lease rail cars and other property and equipment through various leasing arrangements (see Note 8). When we enter into a leasing arrangement, we analyze the terms of the arrangement to determine its accounting treatment. As of December 31, 2015, all leases have been accounted for as operating leases.
We periodically incur costs to improve the assets that we lease under these arrangements. We record the improvement as a component of property and equipment and amortize the improvement over the shorter of the useful life of the improvement or the remaining lease term.
Share-Based Compensation
Our share-based compensation program consists of restricted stock and stock options granted to employees and restricted stock granted to non-employee directors under the SSE 2014 Incentive Plan (the "2014 Plan"). We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. In general, this value is amortized over the vesting period; for grants with a non-
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
substantive service condition, this value is recognized immediately. Amounts are recognized in operating costs and general and administrative expenses.
Income Taxes
Through the effective date of the spin-off, our operations were included in the consolidated federal income tax return and other state returns for CHK. The income tax provision for the period before the spin-off has been prepared on a separate return basis for us and all of our subsidiaries. Accordingly, we have recognized deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases for all our subsidiaries as if each entity were a corporation, regardless of its actual characterization for U.S. federal income tax purposes. Our effective tax rate was 29%, 22% and 28% for the years ended December 31, 2015, 2014 and 2013, respectively. Our effective tax rate can fluctuate as a result of the impact of state income taxes, permanent differences and changes in pre-tax income. Effective with the spin-off, we entered into a tax sharing agreement with CHK which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off, with respect to the payment of taxes, filing of tax returns, reimbursement of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off and other matters regarding taxes. Following the spin-off, we are not entitled to federal income tax net operating loss ("NOL") carryforwards that were generated prior to the spin-off and that have historically been reflected in our net deferred income tax liabilities on our consolidated balance sheet. As of the spin-off date, we made an adjustment to our deferred tax liabilities of approximately $178.8 million to reflect the treatment of NOLs under the tax sharing agreement. In connection with the spin-off, we received a one-time step-up in tax basis of our assets due to the tax gain recognized by CHK related to the spin-off in the tax affected amount of approximately $202.6 million.
A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Based on the expected reversal of our recorded deferred tax liabilities, we had no valuation allowance at December 31, 2015 and 2014.
The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at December 31, 2015 and 2014.
3. Earnings Per Share
Basic earnings per share is computed using the weighted average number of shares of common stock outstanding and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide non-forfeitable dividend rights and are required to be included in the computation of our basic earnings per share using the two-class method. The two-class method is an earnings allocation formula that determines earnings per share for common stock and participating securities according to dividends declared and participation rights in undistributed earnings. Diluted earnings per share is computed using the weighted average shares outstanding for basic earnings per share, plus the dilutive effect of stock options. The dilutive effect of unvested restricted stock and stock options is determined using the treasury stock method, which assumes the amount of unrecognized compensation expense related to unvested share-based compensation awards is used to repurchase shares at the average market price for the period.
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(a)
46,932,433 shares of our common stock were distributed to CHK shareholders on June 30, 2014 in conjunction with the spin-off. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount to be outstanding for periods prior to the spin-off.
(b)
No incremental shares of potentially dilutive restricted stock awards or units were included for periods presented as their effect was antidilutive under the treasury stock method.
(c)
The exercise price of stock options exceeded the average market price of our common stock during the years ended December 31, 2015 and 2014. Therefore, the stock options were not dilutive.
4. Sale of Hodges Trucking Company, L.L.C.
On June 14, 2015, we sold Hodges Trucking Company, L.L.C. (“Hodges”), our previously wholly-owned subsidiary that provided drilling rig relocation and logistics services, to Aveda Transportation and Energy Services Inc. (“Aveda”) for aggregate consideration of $42.0 million. At the time of the sale, Hodges owned 270 rig relocation trucks and 65 cranes and forklifts. The sale did not include the land and buildings used in Hodges’ operations.
The consideration received consisted of $15.0 million in cash and a $27.0 million secured promissory note due June 15, 2020 (the “Note Receivable”). The Note Receivable bears a fixed interest rate of 9.00% per annum, which is payable quarterly in arrears beginning on June 30, 2015. Aveda can, at any time, make prepayments of principal before the maturity date without premium or penalty. The Note Receivable is secured by a second lien on substantially all of Aveda’s fixed assets and accounts receivable. The Note Receivable is presented in other long-term assets on our condensed consolidated balance sheet. During 2015, we recognized interest income of $1.4 million related to the Note Receivable.
We recognized a loss of $35.0 million on the sale of Hodges. Additionally, during 2015, we recognized $2.1 million of additional stock-based compensation expense related to the vesting of restricted stock held by Hodges employees and $0.6 million of severance-related costs.
Hodges was included in our oilfield trucking segment. The sale of Hodges did not qualify as discontinued operations because the sale did not represent a strategic shift that had or will have a major effect on our operations or financial results.
5. Asset Sales and Impairments and Other
Asset Sales
During 2015, we sold our water hauling assets, which consisted of property and equipment that had a total carrying amount of $12.3 million, for $6.5 million. We sold other ancillary equipment for $21.2 million. During 2014, we sold 28 Tier 3 drilling rigs and ancillary drilling equipment for $44.8 million. We sold our crude hauling assets, which included 124 fluid handling trucks and 122 trailers that had a total carrying amount of $20.7 million, for $43.8 million. During 2013, we sold 14
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drilling rigs and ancillary equipment that were not being utilized in our business for $50.6 million, net of selling expenses. We recorded net losses (gains) on sales of property and equipment of approximately $14.7 million, ($6.3) million and ($2.6) million during the years ended December 31, 2015, 2014 and 2013, respectively.
Impairments and Other
A summary of our impairments and other is as follows:
We recognized $2.7 million of impairment charges during the year ended December 31, 2015 for certain trucking and water disposal equipment that we deemed to be impaired based on expected future cash flows of this equipment. Estimated fair value for the trucking and fluid disposal equipment was determined using significant unobservable inputs (Level 3) based on an income approach.
During the years ended December 31, 2014 and 2013, we recognized $11.2 million and $23.6 million, respectively, of impairment charges for certain drilling rigs and spare equipment we had identified to sell as part of our broader strategy to divest of non-essential drilling rigs. We are required to present such assets at the lower of carrying amount or fair value less the anticipated costs to sell at the time they meet the criteria for held for sale accounting. Estimated fair value was based on the expected sales price, less costs to sell.
We also identified certain drilling rigs during the years ended December 31, 2015, 2014 and 2013 that we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. We recorded impairment charges of $5.2 million, $8.4 million and $25.4 million during the years ended December 31, 2015, 2014 and 2013, respectively, related to these drilling rigs. Estimated fair value for these drilling rigs was determined using significant unobservable inputs (Level 3) based on a market approach.
During the year ended December 31, 2014, we purchased 45 leased drilling rigs for approximately $158.4 million and paid lease termination costs of approximately $9.7 million. During the year ended December 31, 2013, we purchased 23 leased drilling rigs for approximately $140.2 million and paid lease termination costs of approximately $22.4 million.
We recognized $8.7 million of impairment charges during the year ended December 31, 2015 for drilling-related services equipment that we deemed to be impaired based on the expected future cash flows of this equipment. The estimated fair value for the drilling-related services equipment was determined using significant unobservable inputs (Level 3) based on a market approach.
We identified certain other property and equipment during the years ended December 31, 2015, 2014 and 2013 that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. We recorded impairment charges of $2.0 million, $1.5 million and $3.4 million during the years ended December 31, 2015, 2014 and 2013, respectively, related to these assets. Estimated fair value for this property and equipment was determined using significant unobservable inputs (Level 3) based on an income approach.
The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management’s judgment. A prolonged period of low oil and natural gas prices or continued reductions in capital expenditures by CHK or our other customers would likely have an adverse impact on our utilization and the prices that we receive for our services. This could result in the recognition of future material impairment charges on the same, or additional, property and
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equipment if future cash flow estimates, based upon information then available to management, indicate that their carrying values are not recoverable.
6. Debt
As of December 31, 2015 and 2014, our long-term debt consisted of the following:
(a)
See Note 2 for applicable disclosures relating to a change in an accounting principle
2019 Senior Notes
In October 2011, we and SSF co-issued $650.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 (the "2019 Notes"). The 2019 Notes will mature on November 15, 2019 and interest is payable semi-annually in arrears on May 15 and November 15 of each year. The 2019 Notes are guaranteed by all of our existing subsidiaries other than certain immaterial subsidiaries and SSF, which is a co-issuer of the 2019 Notes.
We may redeem all or part of the 2019 Notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on November 15 of the years indicated below:
The 2019 Notes are subject to covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets; (2) declare dividends or make distributions on our equity interests or purchase or redeem our equity interests; (3) make investments or other specified restricted payments; (4) incur or guarantee additional indebtedness and issue disqualified or preferred equity; (5) create or incur certain liens; (6) enter into agreements that restrict the ability of our restricted subsidiaries to pay dividends, make intercompany loans or transfer assets to us; (7) effect a merger, consolidation or sale of all or substantially all of our assets; (8) enter into transactions with affiliates; and (9) designate subsidiaries as unrestricted subsidiaries. The 2019 Notes also have cross default provisions that apply to other indebtedness SSE or any of its guarantor subsidiaries may have from time to time with an outstanding principal amount of $50.0 million or more. If the 2019 Notes achieve an investment grade rating from either Moody's Investors Service, Inc. ("Moody's") or Standard & Poor's Rating Services ("S&P"), our obligation to comply with certain of these covenants will be suspended, and if the 2019 Notes achieve an investment grade rating from both Moody's and S&P, all such covenants will terminate.
2022 Senior Notes
In June, 2014, we issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022 (the "2022 Notes"). The 2022 Notes will mature on July 15, 2022 and interest is payable semi-annually in arrears on July 15 and January 15 of each year. Upon the full repayment of the 2019 Notes, the 2022 Notes will be fully and unconditionally guaranteed on a senior unsecured basis by each of our domestic subsidiaries that has outstanding indebtedness or guarantees in an aggregate principal amount greater than $15.0 million. Prior to the full repayment or refinancing of the 2019 Notes, each of our domestic subsidiaries, if any, that has outstanding indebtedness or guarantees in an aggregate principal amount greater than $15.0 million, other than (i) guarantors of the 2019 Notes, (ii) SSO or (iii) subsidiaries of SSO are required to fully and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
unconditionally guarantee the 2022 notes on a senior unsecured basis. We do not have any such subsidiaries currently; therefore, the 2022 Notes are not guaranteed.
We may redeem up to 35% of the 2022 Notes with proceeds of certain equity offerings at a redemption price of 106.5% of the principal amount plus accrued and unpaid interest prior to July 15, 2017, subject to certain conditions. Prior to July 15, 2017, we may redeem some or all of the 2022 Notes at a price equal to 100% of the principal amount plus a make-whole premium determined pursuant to a formula set forth in the indenture governing the 2022 Notes, plus accrued and unpaid interest. On or after July 15, 2017, we may redeem all or part of the 2022 Notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on July 15 of the years indicated below:
The 2022 Notes are subject to covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets; (2) declare dividends or make distributions on our equity interests or purchase or redeem our equity interests; (3) make investments or other specified restricted payments; (4) incur or guarantee additional indebtedness and issue disqualified or preferred equity; (5) create or incur certain liens; (6) enter into agreements that restrict the ability of our restricted subsidiaries to pay dividends, make intercompany loans or transfer assets to us; (7) effect a merger, consolidation or sale of all or substantially all of our assets; (8) enter into transactions with affiliates; and (9) designate subsidiaries as unrestricted subsidiaries. The 2022 Notes also have cross default provisions that apply to other indebtedness of SSE and certain of our subsidiaries. If the 2022 Notes achieve an investment grade rating from either Moody's or S&P, our obligation to comply with certain of these covenants will be suspended, and if the 2022 Notes achieve an investment grade rating from both Moody's and S&P, all such covenants will terminate.
During 2015, we repurchased and cancelled $50.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $31.3 million. We recognized gains on extinguishment of debt of $18.1 million, which reflected the accelerated amortization of deferred financing costs of $0.6 million.
Term Loans
In June 2014, we entered into a $400.0 million seven-year term loan credit agreement. Borrowings under the Term Loan bear interest at our option at either (i) the Base Rate, calculated as the greatest of (1) the Bank of America, N.A. prime rate, (2) the federal funds rate plus 0.50% and (3) a one-month London Interbank Offered Rate ("LIBOR") rate adjusted daily plus 1.00% or (ii) LIBOR, with a floor of 0.75%, plus, in each case, an applicable margin. The applicable margin for borrowings is 2.00% for Base Rate loans and 3.00% for LIBOR loans, depending on whether the Base Rate or LIBOR is used, provided that if and for so long as the leverage ratio is less than a certain level and the term loans have certain ratings from each of S&P and Moody's, such margins will be reduced by 0.25%. As of December 31, 2015, the applicable rate for borrowings under the Term Loan was 3.75%. The Term Loan is repayable in equal consecutive quarterly installments equal to 0.25% (1.00% per annum) of the original principal amount of the Term Loan and will mature in full on June 25, 2021.
Obligations under the Term Loan are guaranteed jointly and severally by all of our present and future direct and indirect wholly-owned material domestic subsidiaries, other than certain excluded subsidiaries. Amounts borrowed under the Term Loan are secured by liens on all of our equity interests in our current and future subsidiaries, and all of our subsidiaries' present and future real property, equipment (including drilling rigs and frac spread equipment), fixtures and other fixed assets.
We may prepay all or a portion of our Term Loan at any time. Borrowings under our Term Loan may be subject to mandatory prepayments with the net cash proceeds of certain issuances of debt, certain asset sales and other dispositions and certain condemnation events, and with excess cash flow in any calendar year in which our leverage ratio exceeds 3.25 to 1.00. The Term Loan contains various covenants and restrictive provisions which limit our ability to (1) enter into asset sales; (2) incur additional indebtedness; (3) make investments or loans and create liens; (4) pay certain dividends or make other distributions and (5) engage in transactions with affiliates.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In May 2015, we entered into an incremental term supplement to the Term Loan and borrowed an additional $100.0 million in aggregate principal amount (the “Incremental Term Loan”), receiving net proceeds of $94.5 million. Borrowings under the Incremental Term Loan bear interest at our option at either (i) LIBOR, with a floor of 1.00% or (ii) the Base Rate, calculated as the greatest of (1) the Bank of America, N.A. prime rate, (2) the federal funds rate plus 0.50% and (3) a one-month LIBOR rate adjusted daily plus 1.00%, plus, in each case, an applicable margin. The applicable margin for borrowings is 9.00% for LIBOR loans and 8.00% for Base Rate loans, depending on whether the Base Rate or LIBOR is used. As of December 31, 2015, the applicable rate for borrowings under the Incremental Term Loan was 10.00%. The Incremental Term Loan is payable in equal consecutive quarterly installments equal to 0.25% (1.00% per annum) of the original principal amount of the Incremental Term Loan and will mature in full on June 25, 2021.
Credit Facilities
In November 2011, we entered into a five-year senior secured revolving bank credit facility with total commitments of $500.0 million. In connection with the spin-off, we repaid in full borrowings outstanding under this credit facility and terminated this credit facility.
In June 2014, we, through SSO, entered into a five-year senior secured revolving bank credit facility with total commitments of $275.0 million. The maximum amount that we may borrow under the credit facility is subject to the borrowing base, which is based on a percentage of eligible accounts receivable, subject to reserves and other adjustments. As of December 31, 2015, the credit facility had availability of $125.5 million, net of letters of credit of $10.2 million. All obligations under the credit facility are fully and unconditionally guaranteed jointly and severally by SSE, and all of our present and future direct and indirect material domestic subsidiaries. Borrowings under the credit facility are secured by liens on cash and accounts receivable of the borrowers and the guarantors, and bear interest at our option at either (i) the Base Rate, calculated as the greatest of (1) the rate of interest publicly announced by Wells Fargo Bank, National Association, as its "prime rate," subject to each increase or decrease in such prime rate effective as of the date such change occurs, (2) the federal funds effective rate plus 0.50% and (3) the one-month LIBOR Rate plus 1.00%, each of which is subject to an applicable margin, or (ii) LIBOR, plus, in each case, an applicable margin. The applicable margin ranges from 0.50% to 1.00% per annum for Base Rate loans and 1.50% to 2.00% per annum for LIBOR loans. The unused portion of the credit facility is subject to a commitment fee that varies from 0.250% to 0.375% per annum, according to average unused amounts. Interest on LIBOR loans is payable at the end of the selected interest period, but no less frequently than quarterly. Interest on Base Rate loans is payable monthly in arrears.
The credit facility contains various covenants and restrictive provisions which limit our ability to (1) enter into asset sales; (2) incur additional indebtedness; (3) make investments or loans and create liens; (4) pay certain dividends or make other distributions and (5) engage in transactions with affiliates. The credit facility requires maintenance of a fixed charge coverage ratio based on the ratio of consolidated EBITDA (minus unfinanced capital expenditures) to fixed charges, in each case as defined in the credit facility agreement, at any time availability is below a certain threshold and for a certain period of time thereafter. If we fail to perform our obligations under the agreement, the credit facility could be terminated and any outstanding borrowings under the credit facility may be declared immediately due and payable. The credit facility also contains cross default provisions that apply to our other indebtedness.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
7. Other Current Liabilities
Other current liabilities as of December 31, 2015 and 2014 are detailed below:
8. Commitments and Contingencies
Operating Leases
As of December 31, 2015, we were party to five lease agreements with various third parties to utilize 725 lease rail cars for initial terms of five to seven years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreement.
As of December 31, 2015, we were also party to various lease agreements for other property and equipment with varying terms.
Aggregate undiscounted minimum future lease payments under our operating leases at December 31, 2015 are presented below:
Rent expense for drilling rigs, real property, rail cars and other property and equipment for the years ended December 31, 2015, 2014 and 2013 was $8.0 million, $35.5 million and $103.9 million, respectively, and was included in operating costs in our consolidated statements of operations.
Other Commitments
Much of the equipment we purchase requires long production lead times. As a result, we typically have outstanding orders and commitments for such equipment. As of December 31, 2015, we had $69.0 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2016.
Litigation
We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, property damage claims and contract actions. We record an associated liability when a loss is probable
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
and can be reasonably estimated. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to our business operations is likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued and actual results could differ materially from management's estimates.
Self-Insured Reserves
We are self-insured up to certain retention limits with respect to workers' compensation and general liability matters. We maintain accruals for self-insurance retentions that we estimate using third-party data and claims history. Included in operating costs is workers' compensation expense of $4.0 million, $8.3 million and $13.6 million for the years ended December 31, 2015, 2014 and 2013, respectively.
9. Share-Based Compensation
Prior to the spin-off, our employees participated in the CHK share-based compensation program and received restricted stock, and in the case of senior management, stock options. Effective July 1, 2014, our employees participate in the SSE 2014 Incentive Plan (the "2014 Plan").
The 2014 Plan authorizes the Compensation Committee of our Board of Directors to grant incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, cash awards and performance awards. No more than 8.4 million shares of SSE common stock may be issued under the 2014 Plan.
In connection with the spin-off, unvested awards granted under the CHK share-based compensation program were cancelled and substituted as follows:
•
Each outstanding award of options to purchase shares of CHK common stock was replaced with a substitute award of options to purchase shares of SSE common stock. The substitute awards of options are intended to preserve the intrinsic value of the original option and the ratio of the exercise price to the fair market value of the stock subject to the option.
•
The CHK restricted stock awards and restricted stock unit awards were replaced with substitute awards in SSE common stock, each of which generally preserved the value of the original award.
Awards granted in connection with the substitution of awards originally issued under the CHK share-based compensation program are a part of the 2014 Plan and reduce the maximum number of shares of common stock available for delivery under the 2014 Plan.
Equity-Classified Awards
Restricted Stock. The fair value of restricted stock awards was determined based on the fair market value of SSE common shares on the date of the grant. This value is amortized over the vesting period.
A summary of the status and changes of the unvested shares of restricted stock under the 2014 Plan is presented below.
As of December 31, 2015, there was $38.1 million of total unrecognized compensation cost related to the unvested restricted stock. The cost is expected to be recognized over a weighted average period of approximately twenty-five months.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Stock Options. CHK granted stock options to our chief executive officer under CHK’s Long-Term Incentive Plan for incentive and retention purposes, which were replaced with a substitute option to purchase shares of SSE common stock in connection with the spin-off. The substitute incentive-based stock options vest ratably over a three-year period and the substitute retention-based stock options will vest one-third on each of the third, fourth and fifth anniversaries of the grant date of the original CHK award. Outstanding options expire ten years from the date of grant of the original CHK award. We have not issued any new stock options, other than the replacement awards, since the spin-off.
The following table provides information related to stock option activity for the year ended December 31, 2015:
(a)
The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
As of December 31, 2015, there was $0.4 million of total unrecognized compensation cost related to stock options. The cost is expected to be recognized over a weighted average period of approximately eleven months.
Through the date of the spin-off we were charged by CHK for share-based compensation expense related to our direct employees. Pursuant to the employee matters agreement with CHK, our employees received a new award under the 2014 Plan in substitution for each unvested CHK award then held (which were cancelled). We recorded a non-recurring credit of $10.5 million to operating costs and general and administrative expenses during the second quarter of 2014 as a result of the cancellation of the unvested CHK awards.
Included in operating costs and general administrative expenses is stock-based compensation expense of $38.5 million, $29.8 million and $13.2 million for the years ended December 31, 2015, 2014 and 2013. Prior to the spin-off, we reimbursed CHK for these costs in accordance with the administrative services agreement. To the extent the compensation cost relates to employees indirectly involved in oilfield services operations, such amounts were charged to us through an overhead allocation and are reflected as general and administrative expenses.
Other
Performance Share Units. CHK granted performance share units ("PSUs") to our chief executive officer under CHK's Long Term Incentive Plan that includes both an internal performance measure and external market condition as it relates to CHK. Following the spin-off, compensation expense is recognized through the changes in fair value of the PSUs over the vesting period with a corresponding adjustment to equity and any related cash obligations are the responsibility of CHK. We recognized (credits) expenses of ($1.6) million, ($0.4) million and $1.4 million related to these PSUs for the years ended December 31, 2015, 2014 and 2013, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
10. Income Taxes
The components of income tax (benefit) expense for each of the periods presented below are as follows:
The effective income benefit differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:
Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. As of the spin-off date, we made an adjustment to our deferred tax liabilities of approximately $178.8 million to reflect the treatment of federal income tax NOL carryforwards under the tax sharing agreement. In connection with the spin-off, we received a one-time step-up in tax basis of our assets due to the tax gain recognized by CHK related to the spin-off in the tax-effected amount of approximately $202.6 million. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
At December 31, 2015, SSE had NOL carryforwards of approximately $469.5 million. The NOL carryforwards expire from 2034 through 2035. The value of these carryforwards depends on the ability of SSE to generate taxable income. We considered both positive and negative evidence in our determination of the need for valuation allowances for the deferred tax assets associated with our NOLs and other deferred tax assets. We determined it is more likely than not that our NOLs and other deferred tax assets will be utilized, and accordingly no valuation allowance has been recorded. However, some or all of these NOLs could expire unused if we are unable to generate sufficient taxable income in the future to utilize them or we enter into transactions that limit our right to use them. We have retained restructuring advisors and are actively exploring and evaluating various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including debt repurchases, exchanges of existing debt securities for new debt securities and exchanges or conversions of existing debt securities into new equity securities, among other options. The outcome of these efforts could potentially reduce our NOLs or limit the use of them in the future. If it became more likely than not NOLs would expire unused, we would have to create a valuation allowance to reflect this fact, which could materially increase our income tax expense, and therefore, adversely affect our results of operations in the period in which it is recorded. We will continue to assess the need for a valuation allowance in the future.
11. Equity Method Investment
We own 49% of the membership interest in Maalt Specialized Bulk, L.L.C. ("Maalt"). Maalt provides bulk transportation, transloading and sand hauling services, and its assets consist primarily of trucks and trailers. We recorded equity method adjustments to our investment of $0.9 million, ($1.6) million and $0.2 million for our share of Maalt's income (loss) for the years ended December 31, 2015, 2014 and 2013, respectively. We also made additional investments of $0.1 million, $0.7 million and $0.4 million during the years ended December 31, 2015, 2014 and 2013, respectively.
We review our equity method investments for impairment whenever certain impairment indicators exist, including the absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment. A loss in value of an investment which is other than a temporary decline should be recognized. Due to further deterioration of industry conditions in the fourth quarter of 2015, we determined that there were indications of impairment present. We estimated that the fair value of our investment in Maalt was zero as of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
December 31, 2015, resulting in a non-cash impairment charge of $8.8 million for the year ended December 31, 2015. We also recognized a non-cash impairment charge of $4.5 million for the year ended December 31, 2014. The impairment charges are included in loss and impairment from equity investees in our condensed consolidated statements of operations. Estimated fair value for our investment in Maalt was determined using significant unobservable inputs (Level 3) based on an income approach.
12. Fair Value Measurements
The fair value measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Authoritative guidance on fair value measurements and disclosures clarifies that a fair value measurement for a liability should reflect the entity's non-performance risk. In addition, a fair value hierarchy is established that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are as follows:
Level 1- Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2- Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3- Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.
Fair Value on Recurring Basis
The carrying values of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.
Fair Value on Non-Recurring Basis
Fair value measurements were applied with respect to our non-financial assets and liabilities measured on a non-recurring basis, which consist primarily of impairments on long-lived assets, goodwill and an equity method investment based on Level 3 inputs. See Notes 2, 5 and 11 for additional discussion.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Fair Value of Other Financial Instruments
The fair value of our note receivable and debt, as shown in the table below, are the estimated amounts a market participant would have to pay to purchase the note receivable or our debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. Estimated fair values are determined by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
(a)
See Note 2 for applicable disclosures relating to a change in an accounting principle
13. Concentration of Credit Risk and Major Customers
Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and trade receivables. Accounts receivable from CHK and its affiliates were $109.6 million and $326.7 million as of December 31, 2015 and December 31, 2014, or 65% and 77%, respectively, of our total accounts receivable. Revenues from CHK and its affiliates were $789.5 million, $1.676 billion and $1.960 billion for the years ended December 31, 2015, 2014 and 2013, or 70%, 81% and 90%, respectively, of our total revenues. We believe that the loss of this customer would have a material adverse effect on our operating results as there can be no assurance that replacement customers would be identified and accessed in a timely fashion.
14. Transactions with CHK
Prior to the completion of our spin-off on June 30, 2014, we were a wholly owned subsidiary of CHK, and transactions between us and CHK (including its subsidiaries) were considered to be transactions with affiliates. Subsequent to June 30, 2014, CHK and its subsidiaries are not considered affiliates of us or any of our subsidiaries. We have disclosed below all agreements entered into between us and CHK prior to the completion of our spin-off.
On June 25, 2014, we entered into a master separation agreement and several other agreements with CHK as part of the spin-off. The master separation agreement entered into between CHK and us governs the separation of our businesses from CHK, the distribution of our shares to CHK shareholders and other matters related to CHK's relationship with us, including cross-indemnities between us and CHK. In general, CHK agreed to indemnify us for any liabilities relating to CHK's business and we agreed to indemnify CHK for any liabilities relating to our business.
On June 25, 2014, we entered into a tax sharing agreement with CHK, which governs the respective rights, responsibilities and obligations of CHK and us with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and certain other matters regarding taxes.
On June 25, 2014, we entered into an employee matters agreement with CHK providing that each company has responsibility for our own employees and compensation plans. The agreement also contains provisions concerning benefit protection for both SSE and CHK employees, treatment of holders of CHK stock options, restricted stock, restricted stock units
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and performance share units, and cooperation between us and CHK in the sharing of employee information and maintenance of confidentiality.
On June 25, 2014, we entered into a transition services agreement with CHK under which CHK provided or made available to us various administrative services and assets for specified periods beginning on the distribution date. In consideration for such services, we paid CHK certain fees, a portion of which was a flat fee, generally in amounts intended to allow CHK to recover all of its direct and indirect costs incurred in providing those services. These charges from CHK were $8.3 million and $18.0 million for the years ended December 31, 2015 and 2014, respectively. This agreement was terminated during the second quarter of 2015.
We are party to a master services agreement with CHK pursuant to which we provide drilling and other services and supply materials and equipment to CHK. Drilling services are typically provided pursuant to rig-specific daywork drilling contracts similar to those we use for other customers. The specific terms of each request for other services are typically set forth in a field ticket, purchase order or work order. The master services agreement contains general terms and provisions, including minimum insurance coverage amounts that we are required to maintain and confidentiality obligations with respect to CHK's business, and allocates certain operational risks between CHK and us through indemnity provisions. The master services agreement will remain in effect until we or CHK provides 30 days written notice of termination, although such agreement may not be terminated during the term of the services agreement described below.
Prior to the spin-off, we were party to a services agreement with CHK under which CHK guaranteed the utilization of a portion of our drilling rig and hydraulic fracturing fleets during the term of the agreement. In connection with the spin-off, we entered into new services agreements with CHK which supplements the master services agreement. Under the new services agreement, CHK is required to utilize the lesser of (i) seven, five and three of our hydraulic fracturing crews in years one, two and three of the agreement, respectively, or (ii) 50% of the total number of all hydraulic fracturing crews working for CHK in all its operating regions during the respective year. CHK is required to utilize our hydraulic fracturing services for a minimum number of stages as set forth in the agreement. CHK is entitled to terminate the agreement in certain situations, including in the event we fail to materially comply with the overall quality of service provided by similar service providers. Additionally, CHK's requirement to utilize our services may be suspended under certain circumstances, such as if we are unable to timely accept and supply services ordered by CHK or as a result of a force majeure event.
In connection with the spin-off, we entered into rig-specific daywork drilling contracts with CHK for the provision of drilling services. The drilling contracts had a commencement date of July 1, 2014 and terms ranging from three months to three years. CHK has the right to terminate the drilling contracts under certain circumstances.
Prior to the spin-off, we were party to a facilities lease agreement with CHK pursuant to which we leased a number of the storage yards and physical facilities out of which we conduct our operations. We incurred $8.2 million and $16.5 million and of lease expense for the years ended December 31, 2014 and 2013, respectively, under this facilities lease agreement. In connection with the spin-off, we acquired the property subject to the facilities lease agreement, and the facilities lease agreement was terminated.
Prior to the spin-off, CHK provided us with general and administrative services and the services of its employees pursuant to an administrative services agreement. These services included legal, accounting, treasury, environmental, safety, information technology and other corporate services. In return for the general and administrative services provided by CHK, we reimbursed CHK on a monthly basis for the overhead expenses incurred by CHK on our behalf in accordance with its allocation policy, which included costs and expenses incurred in connection with the provision of any of the services under the agreement, including the wages and benefits of CHK employees who perform services on our behalf. The administrative expense allocation was determined by multiplying revenues by a percentage determined by CHK based on the historical average of costs incurred on our behalf. All of the administrative cost allocations were based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operating as a stand-alone entity. These charges from CHK were $26.8 million and $55.5 million for the years ended December 31, 2014 and 2013, respectively. In connection with the spin-off, we terminated the administrative services agreement and entered into the transition services agreement described above.
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
15. Segment Information
As of December 31, 2015, our revenues, income (loss) before income taxes and identifiable assets are primarily attributable to three reportable segments. Each of these segments represents a distinct type of business. These segments have separate management teams which report to our chief operating decision maker. The results of operations in these segments are regularly reviewed by our chief operating decision maker for purposes of determining resource allocation and assessing performance. Management evaluates the performance of our segments based upon earnings before interest, taxes, depreciation and amortization, as further adjusted to add back nonrecurring items. The following is a description of the segments and other operations:
Drilling. Our drilling segment provides land drilling services for oil and natural gas E&P activities. As of December 31, 2015, we owned a fleet of 91 land drilling rigs.
Hydraulic Fracturing. Our hydraulic fracturing segment provides hydraulic fracturing and other well stimulation services. Currently, we own 11 hydraulic fracturing fleets with an aggregate of 440,000 horsepower.
Oilfield Rentals. Our oilfield rentals segment provides premium rental tools for land-based oil and natural gas drilling, completion and workover activities.
Former Oilfield Trucking. Our oilfield trucking segment provided drilling rig relocation and logistics services as well as fluid handling services. During the second quarter of 2015, we sold Hodges and our water hauling assets. As part of the spin-off, we sold our crude hauling assets to a third party. As of June 30, 2015, there were no remaining assets or operations in the oilfield trucking segment. Our former oilfield trucking segment's historical results for periods prior to the sale continue to be included in our historical financial results as a component of continuing operations as reflected in the tables below.
Other Operations. Prior to the spin-off, our other operations consisted primarily of our compression unit manufacturing business and corporate functions, including our 2019 Notes, 2022 Notes, Term Loans and credit facilities. As part of the spin-off, we distributed our compression unit manufacturing business to CHK.
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(a)
Includes lease termination costs of $9.7 million and $22.4 million for the years ended December 31, 2014 and 2013, respectively.
16. Condensed Consolidating Financial Information
In October 2011, we issued and sold the 2019 Senior Notes with an aggregate principal amount of $650.0 million (see Note 6). In connection with the spin-off, COO transferred all of its assets, operations, and liabilities, including the 2019 Notes, to SSO, which has been reflected retrospectively in the consolidating financial information. Pursuant to the Indenture governing the 2019 Notes, such notes are fully and unconditionally and jointly and severally guaranteed by SSO's parent, SSE, and all of SSO's material subsidiaries, other than SSF, which is a co-issuer of the 2019 Notes. Each of the subsidiary guarantors is 100% owned by SSO and there are no material subsidiaries of SSO other than the subsidiary guarantors. SSF and Western Wisconsin Sand Company, LLC are minor non-guarantor subsidiaries whose condensed consolidating financial information is included with the subsidiary guarantors. SSE and SSO have independent assets and operations. There are no significant restrictions on the ability of SSO or any subsidiary guarantor to obtain funds from its subsidiaries by dividend or loan.
Set forth below are condensed consolidating financial statements for SSE ("Parent") and SSO ("Subsidiary Issuer") on a stand-alone, unconsolidated basis, and its combined guarantor subsidiaries as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2015
(in thousands)
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2014
(in thousands)
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2015
(in thousands)
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2014
(in thousands)
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2013
(in thousands)
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2015
(in thousands)
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2014
(in thousands)
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2013
(in thousands)
SEVENTY SEVEN ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
17. Quarterly Financial Data (unaudited)
Summarized unaudited quarterly financial data for 2015 and 2014 are as follows:
(a)
Includes $35.0 million of loss on sale of a business for the quarter ended June 30, 2015, $27.4 million of impairment of goodwill for the quarter ended December 31, 2015 and $1.9 million, $1.6 million, $8.8 million and $6.3 million of impairments and other for the quarters ended December 31, 2015, September 30, 2015, June 30, 2015 and March 31, 2015, respectively.
(b)
Includes a non-recurring credit of $10.5 million for the quarter ended June 30, 2014 as a result of the cancellation of the unvested CHK restricted stock and stock option awards and $7.8 million, $3.2 million and $19.8 million of impairments and other for the quarters ended September 30, 2014, June 30, 2014 and March 31, 2014, respectively.
(c)
On June 30, 2014 we distributed 46,932,433 shares of our common stock to CHK shareholders in conjunction with the spin-off. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount to be outstanding for periods prior to the spin-off.
(d)
The sum of quarterly net income per share may not agree to the total for the year as each period's computation is based on the weighted average number of common shares outstanding during each period.
18. Recently Issued and Proposed Accounting Standards
Recently Issued Accounting Standards
In November 2015, the FASB issued ASU No. 2015-17, "Income Taxes," which simplifies the presentation of deferred income taxes by requiring deferred tax liabilities and assets be classified as noncurrent in the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.
In July 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory,” which changes inventory measured using any method other than LIFO or the retail inventory method (for example, inventory measured using first-in, first-out (FIFO) or average cost) at the lower of cost and net realizable value. ASU 2015-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.
In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements-Going Concern,” which requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial
doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). ASU 2014-15 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605)” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; the FASB also provided for early adoption for annual reporting periods beginning after December 15, 2016. We are currently evaluating what impact this standard will have on our consolidated financial statement.
Item 9.
Item 9.
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.
Item 9A.
Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the "Exchange Act") is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer ("CEO") (principal executive officer) and chief financial officer ("CFO") (principal financial officer), as appropriate, to allow for timely decisions regarding required disclosure.
As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures. Based on that evaluation, the CEO and CFO have concluded that those disclosure controls and procedures were effective as of December 31, 2015.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our management, including the CEO and the CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2015 using the criteria established in "Internal Control-Integrated Framework" (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment we concluded that, as of December 31, 2015, our internal control over financial reporting was effective based on the criteria in “Internal Control - Integrated Framework” (2013) issued by the COSO.
The effectiveness of our internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in Item 8 of this Annual Report.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended December 31, 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
/s/ Jerry Winchester
Jerry Winchester
Director, President and Chief Executive Officer
/s/ Cary Baetz
Cary Baetz
Chief Financial Officer and Treasurer
February 17, 2016
Item 9B.
Item 9B.
Other Information
Not applicable.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
Information required by Item 10 of Part III is incorporated herein by reference to the definitive Proxy Statement to be filed by us pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2016 (the "2016 Proxy Statement").
The information required by Item 11
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by Item 12 of Part III is incorporated by reference to the 2016 Proxy Statement.
Item 13.
Item 13.
Certain Relationships and Related Transactions and Director Independence
The information required by Item 13 of Part III is incorporated by reference to the 2016 Proxy Statement.
Item 14.
Item 14.
Principal Accountant Fees and Services
The information required by Item 14 of Part III is incorporated by reference to the 2016 Proxy Statement.
PART IV
Item 15.
Item 15.
Exhibits, Financial Statement Schedules
The following exhibits are filed as a part of this report:
†
Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to any liability under those sections.
*
Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SEVENTY SEVEN ENERGY INC.
Date: February 17, 2016 By: /s/ Jerry Winchester
Jerry Winchester
Director, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
INDEX TO EXHIBITS
†
Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to any liability under those sections.
*
Management contract or compensatory plan or arrangement.