Ranger Energy Services, Inc. - FORM 10-Q

Attached files

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EX-32.1 - EX-32.1 - Ranger Energy Services, Inc.	rngr-20170930ex32148b378.htm
EX-31.2 - EX-31.2 - Ranger Energy Services, Inc.	rngr-20170930ex312b8d222.htm
EX-31.1 - EX-31.1 - Ranger Energy Services, Inc.	rngr-20170930ex311899311.htm

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑Q

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2017

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-38183

RANGER ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)

Delaware	81‑5449572
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

800 Gessner Street, Suite 1000

Houston, Texas 77024

(Address of principal executive offices) (Zip Code)

(713) 935‑8900

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b‑2 of the Exchange Act.

Large accelerated filer ☐		Accelerated filer ☐
Non-accelerated filer ☒	(Do not check if a smaller reporting company)	Smaller reporting company ☐
Emerging growth company☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐ No ☒

As of November 7, 2017, the registrant had 8,413,178 shares of Class A common stock and 6,866,154 shares of Class B common stock outstanding.

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RANGER ENERGY SERVICES, INC.

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		Page


PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Interim Condensed Consolidated Balance Sheets		2
Unaudited Interim Condensed Consolidated Statements of Operations		3
Unaudited Interim Condensed Consolidated Statements of Cash Flows		4
Unaudited Interim Condensed Consolidated Statement of Equity		5
Notes to Unaudited Interim Condensed Consolidated Financial Statements		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
Item 3. Quantitative and Qualitative Disclosures About Market Risk		43
Item 4. Controls and Procedures		43

PART II – OTHER INFORMATION
Item 1. Legal Proceedings		44
Item 1A. Risk Factors		44
Item 6. Exhibits		44

SIGNATURES		47

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PART I – FINANCIAL INFORMATION

ITEM 1. Financial Statements

RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share and per share amounts)


	September 30,		December 31,
Assets	2017		2016
Current assets
Cash and cash equivalents	$	20.7	$	1.6
Restricted cash		0.2		1.8
Accounts receivable, net		24.9		13.4
Unbilled revenues		3.0		1.2
Prepaid expenses and other current assets		6.6		1.4
Assets held for sale		0.6		2.9
Total current assets		56.0		22.3
Property, plant and equipment, net		180.7		102.4
Goodwill		8.6		1.6
Intangible assets, net		11.0		9.2
Other assets		0.7		0.2
Total assets	$	257.0	$	135.7

Liabilities and Stockholders' Equity
Current liabilities
Accounts payable	$	22.3	$	4.7
Accounts payable - related party		—		2.4
Accrued expenses		13.5		2.0
Capital lease obligations, current portion		7.6		0.5
Long-term debt, current portion		1.2		2.3
Total current liabilities		44.6		11.9
Capital lease obligations, less current portion		1.4		0.3
Long-term debt, less current portion		5.8		9.8
Other long-term liabilities		0.9		1.1
Total liabilities		52.7		23.1

Commitments and contingencies (Note 15)

Stockholders' equity / net parent investment
Preferred stock, $0.01 per share; 50,000,000 shares authorized, no shares issued or outstanding as of September 30, 2017; no shares authorized or issued as December 31, 2016		—		—
Class A common stock, $0.01 par value, 100,000,000 shares authorized, 8,413,178 shares issued and outstanding as of September 30, 2017; no shares authorized or issued as of December 31, 2016		0.1		—
Class B common stock, $0.01 par value, 100,000,000 shares authorized, 6,866,154 shares issued and outstanding as of September 30, 2017; no shares authorized or issued as of December 31, 2016		0.1		—
Accumulated deficit		(3.5)		—
Additional paid-in capital		113.2		—
Total stockholders' equity		109.9		—
Non-controlling interest		94.4		—
Net parent investment		—		112.6
Total stockholders' equity/net parent investment		204.3		112.6
Total liabilities and stockholders' equity/net parent investment	$	257.0	$	135.7

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

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RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Revenues
Well Services	$	39.0	$	14.2	$	97.9	$	22.0
Processing Solutions		2.1		1.9		5.9		4.5
Total revenues		41.1		16.1		103.8		26.5

Operating expenses
Cost of services (exclusive of depreciation and amortization shown separately):
Well Services		33.1		11.0		81.1		17.1
Processing Solutions		0.8		0.7		2.2		1.8
Total cost of services		33.9		11.7		83.3		18.9
General and administrative		7.9		2.7		24.0		6.1
Depreciation and amortization		4.1		1.4		11.7		3.1
Total operating expenses		45.9		15.8		119.0		28.1

Operating income (loss)		(4.8)		0.3		(15.2)		(1.6)

Other expenses
Interest expense, net		(4.3)		(0.1)		(5.9)		(0.3)
Total other expenses		(4.3)		(0.1)		(5.9)		(0.3)
Income (loss) before income tax expense		(9.1)		0.2		(21.1)		(1.9)
Tax expense		(0.4)		—		(0.4)		—
Net Income (loss)		(9.5)		0.2		(21.5)		(1.9)
Less: Net income (loss) attributable to the Predecessor		(3.2)		0.2		(15.2)		(1.9)
Less: Net loss attributable to non-controlling interests		(2.8)		—		(2.8)		—
Net loss attributable to Ranger Energy Services, Inc.	$	(3.5)	$	—		(3.5)		—

Loss per common share
Basic	$	(0.42)	$		$	(0.42)	$
Diluted	$	(0.42)	$		$	(0.42)	$
Weighted average common shares outstanding
Basic		8,413				8,413
Diluted		8,413				8,413

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

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RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)


	Nine months ended
	September 30,
	2017		2016
Cash Flows from Operating Activities
Net loss	$	(21.5)	$	(1.9)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization		11.7		3.1
Bad debt expense		0.2		—
Issuance of Class A and Class B common stock for settlement of interest on related party debt		5.2		—
Equity based compensation		0.9		—
Changes in operating assets and liabilities, net of effect of acquisition
Accounts receivable		(5.1)		(2.3)
Unbilled revenue		(1.8)		(0.3)
Prepaid expenses and other current assets		(4.9)		(0.5)
Other assets		(0.7)		-
Accounts payable		1.5		(1.8)
Accounts payable - related party		(2.4)		—
Accrued expenses		9.4		0.9
Other long-term liabilities		(0.1)		—
Net cash used in operating activities		(7.6)		(2.8)

Cash Flows from Investing Activities
Purchase of property, plant and equipment		(16.4)		(5.3)
Acquisitions, net of cash received		(47.7)		—
Net cash used in investing activities		(64.1)		(5.3)

Cash Flows from Financing Activities
Net borrowings under line of credit agreement		—		0.4
Payments on long-term debt		(12.0)		(2.0)
Borrowings on long-term debt		—		0.5
Borrowings on related party debt		21.0		—
Principal payments on capital lease obligations		(0.8)		(0.3)
Proceeds from the Offering, net of underwriters' expense of $4.2 million		80.8		—
Payments incurred for the Offering		(3.8)		—
Contributions from parent		4.0		11.6
Restricted cash		1.6		(1.4)
Net cash provided by financing activities		90.8		8.8

Increase in Cash and Cash equivalents		19.1		0.7
Cash and Cash Equivalents, Beginning of Period		1.6		1.1
Cash and Cash Equivalents, End of Period	$	20.7	$	1.8

Supplemental Cash Flows Information
Interest paid	$	(0.5)	$	(0.4)
Supplemental Disclosure of Noncash Investing and Financing Activity
Non-cash capital expenditures	$	(15.6)	$	(1.6)
Non-cash additions to fixed assets through capital lease financing	$	(9.0)	$	(0.2)
Contribution of Magna	$	—	$	(12.7)
Issuance of Class A and Class B common stock for payment of related party debt	$	(21.0)	$	—
Issuance of Class A common stock for acquisition	$	(5.0)	$	—
Seller's Notes for payment for acquisition	$	(7.0)	$	—

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

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RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENT OF EQUITY
(in millions, except shares)


									Additional				Total		Non
	Class A				Class B				Paid-in		Accumulated		Stockholders'		Controlling		Net Parent		Total
	Shares		Value		Shares		Value		Capital		Deficit		Equity		Interests		Investment		Equity
Balance at December 31, 2016		—	$	—		—	$	—	$	—	$	—	$	—	$	—	$	112.6	$	112.6
Contributions from parent		—		—		—		—		—		—		—		—		4.0		4.0
Equity based compensation		—		—		—		—		—		—		—		0.1		0.8		0.9
Net loss		—		—		—		—		—		(3.5)		(3.5)		(2.8)		(15.2)		(21.5)
Effects of the Offering:
Proceeds from shares sold to public		5,112,069		0.1		—		—		74.1		—		74.2		—		—		74.2
Underwriters fees and discounts		—		—		—		—		(4.2)		—		(4.2)		—		—		(4.2)
Proceeds from shares sold to related parties		750,000		—		—		—		10.9		—		10.9		—		—		10.9
Costs of the Offering		—		—		—		—		(3.8)		—		(3.8)		—		—		(3.8)
Reorganization		1,638,386		—		5,621,491		0.1		23.0		—		23.1		79.1		(102.2)		—
Shares issued for acquisition of ESCO		344,828		—		—		—		5.0		—		5.0		—		—		5.0
Shares issued to pay for related party debt		567,895		—		1,244,663		—		8.2		—		8.2		18.0		—		26.2
Balance at September 30, 2017		8,413,178	$	0.1		6,866,154	$	0.1	$	113.2	$	(3.5)	$	109.9	$	94.4	$	—	$	204.3

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

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RANGER ENERGY SERVICES, INC.
NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND BUSINESS OPERATIONS

Organization

Ranger Energy Services, LLC (“Ranger Services”) was, through Ranger Energy Holdings, LLC (“Ranger Holdings”), formed by CSL Capital Management, LLC (“CSL”) in June 2014 as a provider of high‑spec well service rigs and associated services. Torrent Energy Services, LLC (“Torrent Services” and together with Ranger Services, the “Predecessor Company”) was, through Torrent Energy Holdings, LLC (“Torrent Holdings”), acquired by CSL in September 2014 as a provider of proprietary, modular equipment for the processing of natural gas. In June 2016, CSL indirectly acquired substantially all of the assets of Magna Energy Services, LLC (“Magna”), a provider of well services and wireline services, which it contributed to Ranger Services in September 2016. In October 2016, Ranger Services acquired substantially all of the assets of Bayou Workover Services, LLC (“Bayou”), an owner and operator of high‑spec well service rigs. These condensed consolidated financial statements included in this quarterly report (i) prior to August 16, 2017, the historical financial information of Ranger Services, Torrent Services, Magna and Bayou (collectively, our “Predecessor”), including, as applicable, the results of operations of Magna and Bayou for periods subsequent to their respective acquisitions, and (ii) subsequent to August 16, 2017, the historical information of Ranger Energy Services, Inc. (“Ranger” or the “Company”).

Ranger was incorporated as a Delaware corporation in February 2017. In conjunction with Ranger’s initial public offering (the “Offering”) of Class A Common Stock, par value $0.01 per share (“Class A Common Stock”), which closed on August 16, 2017 and the corporate reorganization described below, Ranger is a holding company, the sole material assets of which consist of membership interests in RNGR Energy Services, LLC a Delaware limited liability company (“Ranger LLC”). Ranger LLC owns all of the outstanding equity interests in Ranger Services and Torrent Services, the subsidiaries through which it operates its assets. Through the consummation of the corporate reorganization, Ranger LLC is the sole managing member of Ranger Services and Torrent Services, and is responsible for all operational, management and administrative decisions relating to Ranger Services and Torrent Services’ business and consolidates the financial results of Ranger Services and Torrent Services and their subsidiaries.

On August 16, 2017, Ranger LLC acquired 49 high-spec well service rigs, certain ancillary equipment, and certain of its liabilities (the “ESCO Acquisition”).

Reorganization

On August 10, 2017, Ranger Services, entered into a Master Reorganization Agreement (the “Master Reorganization Agreement”) with, among others, Ranger LLC, Ranger Holdings, Ranger Energy Holdings II, LLC, a Delaware limited liability company (“Ranger Holdings II”), Torrent Holdings, and Torrent Energy Holdings II, LLC, a Delaware limited liability company (“Torrent Holdings II” and, together with Ranger Holdings, Ranger Holdings II and Torrent Holdings, the “Existing Owners”).

Subject to the terms and conditions set forth in the Master Reorganization Agreement, the parties thereto effected a series of restructuring transactions in connection with the Offering, as a result of which:

(i) Ranger Holdings II and Torrent Holdings II contributed certain of the equity interests in Ranger Services and Torrent Services (together, the “Predecessor Companies”), respectively, to the Company in exchange for an aggregate of 1,683,386 shares of Class A Common Stock and an aggregate of $3.0 million paid to CSL Energy Holdings I, LLC, a Delaware limited liability company, and CSL Energy Holdings II, LLC, a Delaware limited liability company, on or prior to the 18-month anniversary of the consummation of the Offering in, at the Company’s option, cash, shares of Class A Common Stock (with such shares to be valued based on the greater of the initial public offering price of the Class A Common Stock in the Offering and a 30-day volume-weighted average price) or a combination thereof, and the Company contributed such equity interests to Ranger LLC in exchange for 1,638,386 units in Ranger LLC (“Ranger Units”);

(ii) Ranger Holdings and Torrent Holdings contributed the remaining membership interests in the Predecessor Companies to Ranger LLC in exchange for 5,621,491 units in Ranger LLC (“Ranger Units”) and 5,621,491 shares of the

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Company’s Class B common stock, par value $0.01 per share (“Class B Common Stock”), which the Company initially issued and contributed to Ranger LLC;

(iii) the Company contributed all of the net proceeds received by it in the Offering to Ranger LLC in exchange for 5,862,069 Ranger Units;

(iv) Ranger LLC distributed to each of Ranger Holdings and Torrent Holdings one share of Class B Common Stock received pursuant to (ii) above for each Ranger Unit such Existing Owner held; and

(v) as consideration for the termination of certain loan agreements, the Company issued 567,895 shares of Class A Common Stock (in connection with which Ranger LLC issued 567,895 Ranger Units to the Company) and Ranger LLC issued an aggregate of 1,244,663 Ranger Units (and distributed a corresponding number of shares of Class B Common Stock) to the lenders thereof.

The foregoing transactions were undertaken in reliance on an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereof. As a result of these transactions, Ranger LLC became a subsidiary of the Company and the Predecessor Companies became wholly owned subsidiaries of Ranger LLC.

Initial Public Offering

On August 16, 2017, the Company completed the Offering of 5,862,069 shares of its Class A Common Stock. The gross proceeds of the Offering to the Company, based on a public offering price of $14.50 per share, were $85.0 million, which resulted in net proceeds to the Company of $80.8 million, after deducting $4.2 million of underwriting discounts and commissions. The Company received net proceeds of approximately $20.7 million after it paid off the remainder of its long term debt of $10.4 million, funded $45.2 million for the cash portion of the ESCO Acquisition, $3.8 million of costs incurred due to the Offering and $0.7 million for cash bonuses to certain employees.

Business

The Company is one of the largest providers of high‑spec well service rigs and associated services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. The Company’s high‑spec well service rigs facilitate operations throughout the lifecycle of a well, including (i) well completion support, such as milling out composite plugs used during hydraulic fracturing; (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components; and (iv) decommissioning, such as plugging and abandonment operations. The Company also provides rental equipment, including well control packages, hydraulic catwalks and other equipment that are often deployed with its well service rigs. In addition to its core well service rig operations, the Company offers a suite of complementary services, including wireline, snubbing, fluid management and well service-related equipment rentals. In addition, the Company owns and operates a fleet of proprietary, modular natural gas processing equipment that processes rich natural gas streams at the wellhead or central gathering points. The Company has operations in most of the active oil and natural gas basins in the United States, including the Permian Basin, the Denver‑Julesburg Basin, the Bakken Shale, the Eagle Ford Shale, the Haynesville Shale, the Gulf Coast and the SCOOP and STACK plays.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) for interim financial information and the Securities and Exchange Commission’s (“SEC”) instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly certain notes and other information have been condensed or omitted. The unaudited condensed consolidated financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results of operations for the interim periods. These interim financial statements, should be read in conjunction with the consolidated financial statements and related notes for the years ended December 31, 2016 and 2015, included in the final prospectus (the “Final Prospectus”) filed with the Securities and Exchange Commission (the “SEC”) on August 14,

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2017. In management’s opinion, all adjustments necessary for a fair statement are reflected in the interim periods presented. Interim results for the periods presented may not be indicative of results that will realized for future periods.

These financial statements for the period prior to the Offering on August 16, 2017, represent the combined consolidated financial statements of the Predecessor. Subsequent to the Offering the financial statements included in the results of operations reflect the consolidated balances of the Company.

Significant Accounting Policies

Our significant accounting policies are disclosed in Note 2 of the consolidated financial statements for the years ended December 31, 2016 and 2015 included in the Final Prospectus filed with the SEC on August 14, 2017. There have been no changes in such policies or the application of such policies during the three or nine months ended September 30, 2017.

Use of Estimates

The preparation of 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 date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Management uses historical and other pertinent information to determine these estimates. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:

Depreciation and amortization of property, plant and equipment and intangible assets;

Impairment of property, plant and equipment, goodwill and intangible assets;

Allowance for doubtful accounts;

Fair value of assets acquired and liabilities assumed in an acquisition; and

Unit‑based compensation.

Emerging Growth Company status

The Company is an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). The Company will remain an emerging growth company until the earlier of (1) the last day of its fiscal year (a) following the fifth anniversary of the completion of the Offering, (b) in which its total annual gross revenue of at least $1.07 billion, or (c) in which the Company is deemed to be a large accelerated filer, which means the market value of our common stock that is held by non-affiliates exceeds $700.0 million as of the last business day of its most recently completed second fiscal quarter, and (2) the date on which the Company has issued more than $1.0 billion in non-convertible debt securities during the prior three-year period. An emerging growth company may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies. The Company has irrevocably opted out of the extended transition period and, as a result, the Company will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014‑09, Revenue from Contracts with Customers. ASU 2014‑09 supersedes existing revenue recognition requirements in GAAP and requires an entity to recognize revenue when it transfers 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. Additionally, it requires expanded disclosures regarding the nature, amount, timing, and certainty of revenue and cash flows from contracts with customers. The ASU is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted.

The Company is performing its initial assessment of the impact of ASU 2014-09 is expected to have on its current accounting policies, which remains subject to revision following the review and approval of management. The

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implementation of these policies will next require the Company to develop appropriate financial models to permit quantifying the potential impact that application of ASU 2014-09 will have on any previously issued financial statements. Additionally, the implementation of ASU 2014-09 will require training and educating of the Company’s workforce and the investment community regarding the financial statement impact that application of the standard will have based upon the terms of existing contracts and any new contracts that may be executed in the future. The evaluation and modification of existing accounting policies is ongoing, but nearing completion.

In February 2016, the FASB issued ASU No. 2016‑02, Leases, amending the current accounting for leases. Under the new provisions, all lessees will report a right‑of‑use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. All other leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. ASU 2016‑02 is effective for fiscal years beginning after December 15, 2018, including interim periods within that reporting period, using a modified retrospective approach. Early adoption is permitted. The Company is in the initial stages of evaluating the effect of the standard on our consolidated financial statements.

In June 2016, the FASB issued ASU 2016‑13, Financial Instruments—Credit Losses. The amendments in ASU 2016‑13 require the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. In addition, ASU 2016‑13 amends the accounting for credit losses on available‑for‑sale debt securities and purchased financial assets with credit deterioration. The amendment is effective for public entities for annual reporting periods beginning after December 15, 2019, however early application is permitted for reporting periods beginning after December 15, 2018. The Company is in the initial stages of evaluating the effect of the standard on our consolidated financial statements.

In August 2016, the FASB issued ASU 2016‑15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. ASU 2016‑15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. ASU 2016‑15 is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of ASU 2016‑15 on our consolidated financial statements of cash flows.

In January 2017, the FASB issued ASU 2017‑04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. ASU 2017‑04 eliminates the requirement to calculate the implied fair value of goodwill to measure a goodwill impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. The ASU is effective for annual and interim impairment tests performed in periods beginning after December 15, 2019. Early adoption is permitted for annual and interim goodwill impairment testing dates after January 1, 2017. The ASU will be applied prospectively and will impact how we test goodwill for impairment.

In January 2017, the FASB issued ASU 2017‑01, Business Combinations (Topic 805), Clarifying the Definition of a Business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or business. ASU 2017‑01 is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2017 and should be applied prospectively. Early adoption is allowed for transactions that occurred before the issuance date or effective date of the amendments only when the transaction has not been reported in the financial statements previously issued. We currently do not expect that the adoption of this standard will have a material impact on our consolidated financial statements.

NOTE 3. ACQUISITIONS

Magna Acquisition

On June 24, 2016, CSL indirectly acquired substantially all of the assets of Magna, a privately held oilfield services company that provides workover, plug and abandonment, fluid management and wireline services, for an aggregate purchase price of approximately $12.7 million to gain market share in the industry (the “Magna Acquisition”). Magna’s operations are focused primarily in Colorado, Wyoming and North Dakota. Ranger Services accounted for this

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acquisition as a business combination. No goodwill was recorded in conjunction with the Magna Acquisition as the total purchase consideration approximated the fair value of assets acquired and liabilities assumed.

A summary of the fair value of the assets acquired and the liabilities assumed in connection with the Magna Acquisition is set forth below (in millions):


Purchase price
Cash paid by CSL	$	12.7
Total purchase price	$	12.7
Purchase price allocation
Cash	$	1.2
Accounts receivable		3.0
Prepaid expenses and other		1.2
Property, plant and equipment		8.8
Tradename		0.1
Total assets acquired		14.3
Accounts payable		(1.0)
Accrued expenses		(0.6)
Total liabilities assumed		(1.6)
Allocated purchase price	$	12.7

On September 28, 2016, Magna was contributed to Ranger Services by CSL. As this was a transaction among entities under common control, the assets and liabilities were recorded at their historical carrying values from the date of the initial acquisition by CSL on June 24, 2016. The costs related to the transaction were $0.1 million and were expensed during 2016 and are included in the Company’s condensed consolidated statements of operations for the three and nine months ended September 30, 2016.

Bayou Acquisition

On October 3, 2016, Ranger Services acquired Bayou, a privately held oilfield services company that provides workover, plug and abandonment and fluid management services, for an aggregate purchase price of approximately $50.5 million, which included an approximate 35% equity interest in Ranger Services (the “Bayou Acquisition”). Bayou’s operations are focused primarily in Colorado and North Dakota. Ranger accounted for this acquisition as a business combination.

A summary of the fair value of the assets acquired and the liabilities assumed in connection with the Bayou Acquisition is set forth below (in millions):


Purchase price
Cash	$	17.5
Equity issued		33.0
Total purchase price	$	50.5
Purchase price allocation
Prepaid expenses & other	$	0.5
Property, plant and equipment		40.0
Land		0.6
Building and site improvements		2.3
Customer relationships		9.3
Total assets acquired		52.7
Accounts payable		(1.8)
Accrued expenses		(1.0)
Other long‑term liabilities		(1.0)
Total liabilities assumed		(3.8)
Goodwill		1.6
Allocated purchase price	$	50.5

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Goodwill represents trained and assembled workforce which does not meet the separability criterion. The costs related to the transaction were $0.4 million and were expensed during 2016 in the Company’s combined consolidated statements of operations for the year ended December 31, 2016.

ESCO Acquisition

In connection with the closing of our offering on August 16, 2017, the Company closed on the ESCO Acquisition for total consideration of $59.7 million, consisting of $47.7 million in cash, $7.0 million in secured seller notes and $5.0 million in shares of Ranger’s Class A Common Stock based on the initial public offering price of $14.50 per share.

The ESCO Acquisition assets were primarily engaged in the completion, repair and workover of oil and gas wells for its customers. The ESCO Acquisition is being accounted for as a business combination. Goodwill is recorded in conjunction with the ESCO Acquisition as the total purchase consideration exceeds the approximated fair value of assets acquired and liabilities assumed.

The following information below represents the preliminary purchase allocation related to the ESCO Acquisition (in millions):


Purchase price
Cash	$	47.7
Seller's notes		7.0
Equity issued		5.0
Total purchase price	$	59.7
Purchase price allocation
Cash	$	-
Accounts receivable		6.6
Property, plant and equipment		45.9
Intangible assets		2.2
Other assets		0.4
Total assets acquired		55.1
Accounts payable		(0.5)
Accrued expenses		(1.9)
Total liabilities assumed		(2.4)
Goodwill		7.0
Allocated purchase price	$	59.7

The following is supplemental pro-forma revenue, operating loss, and net loss had the ESCO Acquisition occurred as of January 1, 2016 (in millions):


		Nine Months Ended September 30,
	2017			2016
Supplemental Pro Forma:
Revenue		$	126.5		$	90.4
Operating Loss		$	(17.2)		$	(19.4)
Net Loss		$	(23.7)		$	(26.7)

The supplemental pro forma revenue, operating loss, and net loss are presented for informational purposes only and may not necessarily reflect the future results of operations of the Company or what the results of operations would have been had the Company owned and operated Magna, Bayou and the ESCO Acquisition assets since January 1, 2016. There are no material non-recurring adjustments included in these supplemental pro forma items.

We reported revenue during the three and nine months ended September 30, 2017 that included $5.4 million generated from the assets acquired in connection with the ESCO Acquisition.

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NOTE 4. ASSETS HELD FOR SALE

During the year ended December 31, 2016, the Company decided to market and sell non‑core rental fleet assets. The units consisted of Mechanical Refrigerator Units (“MRUs”), stabilizers and wedge units, and were classified as held for sale due to the fact that they were specifically identified, and management has a plan for their sale in their present condition to occur in the next year. As of September 30, 2017, the Company moved the MRUs and stabilizers with a net book value of $2.3 million back into operating assets. The wedge units representing the remaining balance of $0.6 million are still classified as held for sale. The available for sale assets are recorded at the units’ carrying amount, which approximates fair value less costs to sell, and are no longer depreciated.

NOTE 5. PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment include the following (in millions):


	Estimated
	Useful Life	September 30,		December 31,
	(years)	2017		2016
Machinery and equipment	5 - 30	$	2.3	$	3.0
Vehicles	3 - 5		1.6		0.2
Mechanical refrigeration units	30		18.2		16.0
NGL storage tanks	15		4.3		4.3
Workover rigs	5 - 20		161.5		73.8
Other property, plant and equipment	3 - 30		12.4		13.8
Property, plant and equipment			200.3		111.1
Less: accumulated depreciation			(19.6)		(8.7)
Property, plant and equipment, net		$	180.7	$	102.4

Depreciation expense was $11.3 million and $3.1 million for the nine months ended September 30, 2017 and 2016, respectively. Depreciation expense was $3.9 million and $1.4 million for the three months ended September 30, 2017 and 2016, respectively.

NOTE 6. GOODWILL AND INTANGIBLE ASSETS

Goodwill was $8.6 million and $1.6 million as of September 30, 2017 and December 31, 2016, respectively. During 2017, $7.0 million of goodwill was recognized in connection with the ESCO Acquisition. During 2016, $1.6 million of goodwill was recognized in connection with the Bayou Acquisition.

Definite lived intangible assets are comprised of the following (in millions):


	Estimated
	Useful Life	September 30,		December 31,
	(years)	2017		2016
Tradenames	3	$	0.1	$	0.1
Customer relationships	15 - 18		11.4		9.2
Less: accumulated amortization			(0.5)		(0.1)
Intangible assets, net		$	11.0	$	9.2

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Amortization expense was $0.4 million and $0.0 million for the nine months ended September 30, 2017 and 2016, respectively. Amortization expense was $0.2 and $0.0 million for the three months ended September 30, 2017 and 2016, respectively. Amortization expense for the future periods is expected to be as follows (in millions):


As of September 30,	Amount
2017	$	0.2
2018		0.6
2019		0.6
2020		0.6
2021		0.6
Thereafter		8.4
	$	11.0

NOTE 7. ACCRUED EXPENSES

Accrued expenses include the following (in millions):


	September 30,		December 31,
	2017		2016
Accrued payables	$	4.6	$	1.2
Accrued payroll		3.8		0.1
Accrued taxes		1.6		0.7
Accrued insurance		3.5		—
Total accrued expenses	$	13.5	$	2.0

NOTE 8. CAPITAL LEASES

The Company leases certain assets under capital leases which expire at various dates through 2020. The assets and liabilities under capital leases are recorded at the lower of present value of the minimum lease payments or the fair value of the assets. The assets are amortized over the shorter of the estimated useful lives or over the lease term. Amortization expense of assets under capital leases was $1.2 million and $0.4 million for the nine months ended September 30, 2017 and 2016, respectively. Amortization expense of assets under capital leases was $0.4 million and $0.2 million for the three months ended September 30, 2017 and 2016, respectively.

In February 2017, the Company entered into a lease agreement for certain high‑specification rig equipment for use in its business operations. The lease is being accounted for as a capital lease, as the present value of minimum monthly lease payments, including the purchase option, exceeds 90 percent of the fair value of the leased property at inception of the lease. The lease term ends January 2018, and as such, the total obligation is current.

Aggregate future minimum lease payments under capital leases are as follows (in millions):


As of September 30,	Total
2017	$	0.5
2018		8.0
2019		0.7
2020		0.4
Total future minimum lease payments		9.6
Less: amount representing interest		(0.6)
Present value of future minimum lease payments		9.0
Less: current portion of capital lease obligations		(7.6)
Total capital lease obligations, less current portion	$	1.4

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NOTE 9. LONG‑TERM DEBT

Long‑term debt consists of the following (in millions):


	September 30,		December 31,
	2017		2016
Term loans	$	—	$	7.1
Other long-term debt		7.0		—
Revolver		—		5.0
Current portion of long-term debt		(1.2)		(2.3)
Long term-debt, less current portion	$	5.8	$	9.8

Ranger Services had a $2.0 million revolving line of credit with Iberia Bank expiring on April 30, 2018 (the “Revolver”). On December 23, 2016, Ranger Services amended the Revolver to increase its size to $5.0 million. As of December 31, 2016, there was $5.0 million borrowed against the Revolver. The Revolver was secured by substantially all of Ranger Service’s assets (approximately $107.9 million of the Predecessor’s total assets as of December 31, 2016).As of September 30, 2017, the Company paid the remaining balances and the Revolver has been closed. Interest varied with the bank’s prime rate and the bank’s London Interbank Offered Rate (“LIBOR”). At December 31, 2016, the interest rate was 4.12%.

In February 2015, as amended in March 2016, Torrent Services secured a $2.0 million senior credit facility with Texas Capital Bank consisting of a $2.0 million advancing term loan as defined by the note agreement. The note was secured by all of Torrent Services’ assets (approximately $27.8 million of the Predecessor’s total assets as of December 31, 2016. Interest varied with the bank’s prime rate and the bank’s LIBOR and was payable quarterly through maturity of the note). As of December 31, 2016, the interest rate was 5.75%. As of December 31, 2016, there was $0.7 million outstanding on the senior credit facility. As of September 30, 2017 the senior credit facility has no outstanding balance and has been subsequently closed.

In March 2015, Torrent Services, through certain members of its management team as borrowers, secured a $0.6 million promissory note with Benchmark Bank. Interest varied with the bank’s prime rate. Initially, all principal and interest was due on the date of maturity of September 4, 2015, however, the terms were renegotiated and a restructured note and agreement was entered into in April 2016 with an interest rate of 4.5%. In April 2016 Torrent Services made a principal payment of $0.4 million on this promissory note, leaving a remaining balance of $0.2 million which was secured by a $0.2 million certificate of deposit. As of December 31, 2016, there was $0.2 million outstanding on the promissory note. The remaining principal balance was repaid in full on February 28, 2017.

In April 2015, Ranger Services secured a $7.0 million promissory note with Iberia Bank. Interest varied with the bank’s prime rate and the bank’s LIBOR and was payable in 60 equal monthly installments, which commenced on May 1, 2016. As of December 31, 2016, the outstanding balance was $6.2 million. As of September 30, 2017, this promissory note has no outstanding balance and has been subsequently closed.

In connection with the Offering and the ESCO Acquisition the Company issued $7.0 million of seller’s notes as partial consideration for the ESCO Acquisition. These notes include a note for $1.2 million due on August 16, 2018 and a note for $5.8 million due on February 16, 2019. Both of these notes bear interest at 5.0% payable quarterly until their respective maturity dates.

On August 16, 2017, in connection with the Offering, Ranger entered into a $50.0 million senior revolving credit facility (the “Credit Facility”)by and among certain of Ranger’s subsidiaries, as borrowers, each of the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent (the “Administrative Agent”). The credit facility is subject to a borrowing base that is calculated by us based upon a percentage of the value of our eligible accounts receivable less certain reserves.

The Credit Facility permits extensions of credit up to the lesser of $50.0 million and a borrowing base that is determined by calculating the amount equal to the sum of (i) 85% of the Eligible Accounts (as defined in the Credit Facility), less the amount, if any, of the Dilution Reserve (as defined in the Credit Facility), minus (ii) the aggregate amount of Reserves (as defined in the Credit Facility), if any, established by the Administrative Agent from time to time pursuant to the Credit Facility. The borrowing base is calculated on a monthly basis pursuant to a borrowing base

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certificate delivered by the Borrower to the Administrative Agent. The Company has approximately $20 million of borrowing capacity under the Credit Facility.

Borrowings under the Credit Facility bear interest, at the Company’s election, at either the (a) one-, two-, three- or six-month LIBOR or (b) the greatest of (i) the federal funds rate plus ½%, (ii) the one-month LIBOR plus 1% and (iii) the Administrative Agent’s prime rate (the “Base Rate”), in each case plus an applicable margin, and interest shall be payable monthly in arrears. The applicable margin for LIBOR loans ranges from 1.50% to 2.00% and the applicable margin for Base Rate loans ranges from 0.50% to 1.00%, in each case, depending on the Company’s average excess availability under the Credit Facility. The applicable margin for LIBOR loans are 1.50% and the applicable margin for Base Rate loans are 0.50% until August 31, 2018. During the continuance of a bankruptcy event of default, automatically and during the continuance of any other default, upon the Administrative Agent’s or the required lenders’ election, all outstanding amounts under the Credit Facility bears interest at 2.00% plus the otherwise applicable interest rate. The Credit Facility is scheduled to mature on August 16, 2022.

In addition, the Credit Facility restricts the Company’s ability to make distributions on, or redeem or repurchase, our equity interests, except for certain distributions, including distributions of cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Facility and either (a) excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 22.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $10.0 million or (b) if our fixed charge coverage ratio is at least 1.0x on a pro forma basis, excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 17.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $7.0 million. If the foregoing threshold under clause (b) is met, the Company may not make such distributions (but may make certain other distributions, including under clause (a) above) prior to the earlier of the date that is (a) 12 months from closing or (b) the date that the Company’s fixed charge coverage ratio is at least 1.0x for two consecutive quarters. The Credit Facility generally permits the Company to make distributions required under the Tax Receivable Agreement (as defined in Note 16), but a ‘‘Change of Control’’ under the Tax Receivable Agreement constitutes an event of default under the Credit Facility, and the Credit Facility does not permit the Company to make payments under the Tax Receivable Agreement upon acceleration of our obligations thereunder unless no event of default exists or would result therefrom and we have been in compliance with the fixed charge coverage ratio for the most recent 12-month period on a pro forma basis. The Credit Facility also requires the Company to maintain a fixed charge coverage ratio of at least 1.0x if the Company’s liquidity is less than $10.0 million until the Company’s liquidity is at least $10.0 million for thirty consecutive days. The Company is not be subject to a fixed charge coverage ratio if it has no drawings under the Credit Facility and has at least $20.0 million of qualified cash.

The Credit Facility contains events of default customary for facilities of this nature, including, but not limited, to:

• events of default resulting from our failure or the failure of any guarantors to comply with covenants and financial ratios;

• the occurrence of a change of control;

• the institution of insolvency or similar proceedings against the Company or any guarantor; and

• the occurrence of a default under any other material indebtedness the Company or any guarantor may have.

Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Facility, the lenders are able to declare any outstanding principal of the Credit Facility debt, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies.

As of September 30, 2017, the Company has not borrowed any funds under the Credit Facility. The Company is in compliance with the Credit Facility covenants as of September 30, 2017.

The Company capitalized fees of $0.7 million associated with the Credit Facility described above, which are included on the Unaudited Interim Condensed Consolidated Balance Sheets as other assets, and will amortize these fees over the life of the Credit Facility. Unamortized debt issuance costs as of September 30, 2017 totals $0.7 million.

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In addition the Company converted all of its related party debt to equity in connection with the pre-offering reorganization, see Note 16 – Related Party Transactions.

NOTE 10. RISK CONCENTRATIONS

Customer Concentrations

For the nine months ended September 30, 2017, two customers (EOG Resources and PDC Energy—Well Services segment) accounted for approximately 13.4% and 18.9%, respectively, of the Company’s total revenues. For the three months ended September 30, 2017, two customers (EOG Resources and PDC Energy—Well Services segment) accounted for approximately 11.5% and 12.3%, respectively, of the Company’s total revenues. At September 30, 2017, approximately 21.7% of the accounts receivable balance was due from these customers.

For the nine months ended September 30, 2016, two customers (EOG Resources and PDC Energy —Well Services segment) accounted for 30.8% and 19.2%, respectively, of the Company’s total revenues. For the three months ended September 30, 2016, two customers (EOG Resources and PDC Energy—Well Services segment) accounted for approximately 17.2% and 26.0%, respectively, of the Company’s total revenues. At September 30, 2016, approximately 28.5% of the accounts receivable balance was due from these customers.

NOTE 11. EQUITY BASED COMPENSATION AND PROFIT INTERESTS AWARDS

Long-term Incentive Plan

On August 10, 2017, the Board adopted the Ranger Energy Services, Inc. 2017 Long-term Incentive Plan (“LTIP”) for the employees, consultants and the directors of the Company and its affiliates who perform services for the Company. The LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws; (ii) nonstatutory stock options that do not qualify as incentive stock options; (iii) stock appreciation rights; (iv) restricted stock awards; (v) restricted stock units; (vi) bonus stock; (vii) performance awards; (viii) dividend equivalents; (ix) other stock-based awards; (x) cash awards; and (xi) substitute awards. Subject to adjustment in accordance with the terms of the LTIP, 1,250,000 shares of Class A Common Stock have been reserved for issuance pursuant to awards under the LTIP. Class A Common Stock withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP will be administered by the Board or an alternative committee appointed by the Board. As of September 30, 2017 there have been no awards granted under the LTIP.

Well Services

The Well Services segment was 100% owned by Ranger Holdings and Ranger Services’ equity was represented by a single share class. Ranger Holdings has issued Class C and Class D units to certain key employees of Ranger Services as remuneration for employee services that were originally intended, at grant, to be “profit interests” with no voting rights. Certain of the units vest 33% per year over a three‑year service period and may be forfeited or repurchased by Ranger Holdings under certain circumstances as set forth in the Ranger Holdings limited liability company agreement and the individual Class C and Class D unit grant agreements. The “vesting units” are deemed equity and are measured at fair value using an option pricing model at each grant date with compensation expense recognized on a straight‑line basis over the requisite service period.

Certain of the Class C and Class D units that were granted are liability‑classified awards as they do not fully vest until a defined change of control event. The Company has not recognized a liability or recognized any compensation expense for these liability‑classified awards in the accompanying unaudited condensed consolidated financial statements since the change of control event is not probable and estimable. These units will trigger no compensation expense until amounts payable under such awards become probable and estimable.

On October 3, 2016, the Class C and Class D units were modified, whereby new units were issued to replace the existing Class C and Class D units that had been issued prior to October 3, 2016. As part of the issuance of the new

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Class C and Class D unit, the existing Class C and Class D units were cancelled. The terms of the new and existing Class C and Class D awards were materially similar.

The grant date fair value for the Class C and Class D units prior to modification were de minimis while the grant date fair value for the Class C and Class D units at modification was $2.5 million. There were additional grants to specific employees during the three and nine months ended September 30, 2017 of approximately $1.6 million. During the nine months ended September 30, 2017 and 2016, we recognized compensation expense of $0.8 million and $0.0 million, respectively. During the three months ended September 30, 2017 and 2016, we recognized compensation expense of $0.2 million and $0.0 million, respectively. The total unrecognized compensation cost related to unvested awards at September 30, 2017 is $1.6 million and is expected to be recognized over the next two years.

The following table summarizes the Class C and Class D unit activity for the year ended December 31, 2016 and for the nine months ended September 30, 2017 (in millions):


	Class C units		Class D units
	Equity-based		Equity-based
	Compensation	Liability	Compensation	Liability
	Awards	Awards	Awards	Awards
Outstanding at January 1, 2016	0.5	0.2	0.4	0.2
Granted	—	—	—	—
Forfeited	—	—	—	—
Outstanding at December 31, 2016	0.5	0.2	0.4	0.2
Granted	0.3	—	0.3	—
Forfeited	(0.2)	—	(0.3)	—
Outstanding at September 30, 2017	0.6	0.2	0.4	0.2

We utilized an option pricing model to estimate grant date fair value of the equity‑based compensation awards, which included probability of various outcomes. Expected volatilities are based on historical volatilities of the stock of comparable companies in our industry. The risk‑free rate for periods within the contractual life of the award is based on the U.S. Treasury yield curve in effect at the time of grant. Actual results may vary depending on the assumptions applied within the model. The following table presents the assumptions used in the valuation and resulting grant date fair value:


	2016
	Pre-Modification		At Modification		2017
Period	5 years		5 years		5 years
Dividend Yield	—	%	—	%	—	%
Volatility	35 - 60	%	40	%	40	%
Risk Free Rate	1.0 - 1.6	%	1.2	%	1.2	%

Processing Solutions

The Processing Solutions segment was 100% owned by Torrent Holdings and Torrent Services’ equity was represented by a single share class. Torrent Holdings has issued Class B and Class C units to certain key employees of Torrent as remuneration for employee services that were originally intended, at grant, to be “profit interests” with no voting rights. Class B units have a three‑year vesting period at 25% per year, with the remaining 25% vesting upon certain events occurring. Torrent Holdings also issued Class C awards, which were fully vested at grant date when issued in 2014. Class B and Class C units are deemed to be equity‑classified.

The grant date fair value for the Class B and Class C unit awards were $0.3 million and $0.1 million, respectively. Compensation expense is recognized on a straight‑line basis over the requisite service period. During the three months ended September 30, 2017 and 2016, we recognized compensation expense of less than $0.1 million and $0 million, respectively. The total unrecognized compensation cost related to unvested awards at September 30, 2017 is less than $0.1 million and is expected to be recognized in 2017. There were 0.3 million units granted during the nine months ended September 30, 2017 and none during the three months ended September 30, 2017.

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The following table summarizes the Class B and Class C unit activity for the year ended December 31, 2016 and for the nine months ended September 30, 2017 (in millions):


	Class B	Class C(1)
Outstanding at January 1, 2016	1.0	—
Granted	—	—
Forfeited	(0.3)	—
Outstanding at December 31, 2016	0.7	—
Granted	0.3	—
Forfeited	—	—
Outstanding at September 30, 2017	1.0	—

(1)There were 2,000 Class C units outstanding at each date.


	Assumptions
Period	2.8	years
Dividend Yield	—	%
Volatility	28.1	%
Risk Free Rate	0.9	%

NOTE 12. INCOME TAXES

The Company is a corporation and is subject to U.S. federal income tax. The tax implications of the Offering and the Company’s concurrent corporate reorganization, and the tax impact of the Company’s status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying condensed consolidated financial statements. The effective U.S. federal income tax rate applicable to the Company for the nine months ended September 30, 2017 and 2016 was 0.0%. Total income tax expense for the three and nine months ended September 30, 2017 differed from amounts computed by applying the U.S. federal statutory tax rate of 35% due primarily to the impact of recording a valuation allowance against the tax benefit of the net loss. The Company is subject to the Texas Margin Tax that requires tax payments at a maximum statutory effective rate of 0.75% on the taxable margin of each taxable entity that does business in Texas.

As a result of the Offering and subsequent reorganization, the Company recorded a deferred tax asset; however, a full valuation allowance has been recorded to reduce the Company’s net deferred tax assets to an amount that is more likely than not to be realized and is based upon the uncertainty of the realization of certain federal and state deferred tax assets related to net operating loss carryforwards and other tax attributes.

NOTE 13. NON-CONTROLLING INTERESTS

The Company has ownership interests in Ranger LLC, which is consolidated within the Company’s financial statements but is not wholly owned by the Company. During the nine months ended September 30, 2017, the Company reports a non-controlling interest representing the Ranger Units. Changes in the Company’s ownership interest in Ranger LLC while it retains its controlling interest are accounted for as equity transactions.

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NOTE 14. LOSS PER SHARE

Loss per share is based on the amount of income allocated to the shareholders and the weighted average number of shares outstanding during the period for each class of common stock.

Losses related to periods prior to the reorganization and the Offering are attributable to the Predecessor. The following table presents the Company’s calculation of basic and diluted loss per share for the three and nine months ended September 30, 2017 and 2016 (dollars in millions, except share and per share amounts):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Loss (numerator):
Basic:
Net loss attributable to Ranger Energy Services, Inc.	$	(3.5)	$	—	$	(3.5)	$	—
Less: Net loss attributable to class B common stock		—		—		—		—
Net loss attributable to class A common stock		(3.5)		—		(3.5)		—

Diluted:
Net loss attributable to Ranger Energy Services, Inc.	$	(3.5)	$	—	$	(3.5)	$	—
Less: Net loss attributable to class B common stock		—		—		—		—
Net loss attributable to class A common stock		(3.5)		—		(3.5)		—

Weighted average shares (denominator):
Weighted average number of shares - basic and diluted		8,413,178		—		8,413,178		—

Basic loss per share		$ (0.42)		—		$ (0.42)		—

Diluted loss per share		$ (0.42)		—		$ (0.42)		—

For the periods presented, the Company excluded 6.9 million shares of common stock issuable upon conversion of the Company’s Class B common stock in calculating diluted loss per share, as the effect was anti-dilutive.

NOTE 15. COMMITMENTS AND CONTINGENCIES

Legal Matters

From time to time, the Company is involved in various legal matters arising in the normal course of business. The Company does not believe that the ultimate resolution of these matters will have a material adverse effect on its condensed consolidated financial position or results of operations.

Employee Severance

In March 2017, Ranger Services terminated the employment of one of its officers. As a result, the former officer became entitled to severance payments of $0.7 million. In addition during the nine months ended September 30, 2017, Ranger Services severed other officers and employees. As of September 30, 2017, Ranger Services has $0.5 million of severance liability recorded in the accompanying condensed consolidated financial statements.

NOTE 16. RELATED PARTY TRANSACTIONS

Stockholders’ Agreement

In connection with the Offering, Ranger entered into a stockholders’ agreement (the “Stockholders’ Agreement”) with the Existing Owners and the Bridge Loan Lenders (defined below). Among other things, the Stockholders’ Agreement provides CSL and Bayou Wells Holdings Company, LLC (“Bayou Holdings”) with the right

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to designate nominees to Ranger’s board of directors (each, as applicable, a “CSL Director” or “Bayou Director”) as follows:

for so long as CSL beneficially owns at least 50% of Ranger’s common stock, at least three members of the board of directors shall be CSL Directors and at least two members of the board of directors shall be Bayou Directors (which may include Richard Agee, Brett Agee or any other person that may be designated by Bayou Holdings in accordance with the terms of the stockholders’ agreement);

for so long as CSL beneficially owns less than 50% but at least 30% of Ranger’s common stock, at least three members of the board of directors shall be CSL Directors;

for so long as CSL beneficially owns less than 30% but at least 20% of Ranger’s common stock, at least two members of the board of directors shall be CSL Directors;

for so long as CSL beneficially owns less than 20% but at least 10% of Ranger’s common stock, at least one member of the board of directors shall be a CSL Director; and

once CSL beneficially owns less than 10% of Ranger’s common stock, CSL will not have any board designation rights.

In the event the size of Ranger’s board of directors is increased or decreased at any time to other than eight directors, CSL’s nomination rights will be proportionately increased or decreased, respectively, rounded up to the nearest whole number.

Employee Matters Agreement

In connection with the Bayou Acquisition, Ranger Services and Ranger Holdings entered into an Employee Matters Agreement in October 2016 (the “EMA”) with Bayou Holdings and its affiliates (collectively, the “Bayou Parties”). Pursuant to the EMA, the Bayou Parties seconded certain employees to Ranger Services and Ranger Holdings from October 4, 2016 to December 31, 2016 to perform certain transition services. In exchange for receiving these seconded employees and related services, Ranger Services and Ranger Holdings paid the Bayou Parties approximately $5.8 million through December 31, 2016. As of December 31, 2016, Ranger Services and Ranger Holdings had accounts payable to the Bayou Parties of approximately $2.4 million, which were paid in full in March 2017. Bayou Holdings is controlled by Messrs. Brett and Richard Agee, each of whom is a manager of Bayou Holdings and member of Ranger’s board of directors.

Redemption Rights

Under the Ranger, holders of Ranger Units (the “Ranger Unit Holders”) (other than Ranger) will, subject to certain limitations, have the right, pursuant to the Redemption Right (as defined in the Ranger LLC Agreement), to cause Ranger LLC to acquire all or a portion of their Ranger Units (along with a corresponding number of shares of Ranger’s Class B common stock) for, at Ranger LLC's election, (i) shares of Ranger’s Class A common stock at a redemption ratio of one share of Class A common stock for each Ranger Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends, reclassification and other similar transactions, or (ii) cash in an amount equal to the Cash Election Value (defined below) of such Class A common stock. The Company will determine whether to issue shares of Class A common stock or cash in an amount equal to the Cash Election Value based on facts in existence at the time of the decision, which Ranger expects would include the trading prices for the Class A common stock at the time relative to the cash purchase price for the Ranger Units, the availability of other sources of liquidity (such as an issuance of preferred stock) to acquire the Ranger Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, Ranger (instead of Ranger LLC) will have the right, pursuant to the Call Right (as defined in the Ranger LLC Agreement), to, for administrative convenience, acquire each tendered Ranger Unit directly from such Ranger Unit Holder for, at Ranger’s election, (x) one share of Class A common stock or (y) cash in an amount equal to the value of a share of Class A common stock, based on a volume-weighted average price. In addition, upon a change of control of Ranger, Ranger has the right to require each Ranger Unit Holder (other than Ranger) to exercise its Redemption Right with respect to some or all of such unitholder's Ranger Units. As the Ranger Unit Holders redeem their Ranger Units, Ranger’s membership interest in Ranger LLC will be correspondingly increased, the number of

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shares of Class A common stock outstanding will be increased, and the number of shares of Class B common stock outstanding will be reduced.

Ranger’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of Ranger Units pursuant to an exercise of the Redemption Right or the Call Right is expected to result in adjustments to the tax basis of the tangible and intangible assets of Ranger LLC, and such adjustments will be allocated to the Company. These adjustments would not have been available to Ranger absent the acquisition or deemed acquisition of Ranger Units and are expected to reduce the amount of cash tax that Ranger would otherwise be required to pay in the future.

“Cash Election Value" means, with respect to the shares of Class A common stock to be delivered to the redeeming Ranger Unit Holder by us pursuant to our Call Right, the amount that would be received if the number of shares of Class A common stock to which the redeeming Ranger Unit Holder would otherwise be entitled were sold at a per share price equal to the trailing 10-day volume weighted average price of a share of Class A common stock on such redemption, net of actual or deemed offering expenses.

Payments

The Company incurred approximately $0.4 million and $0.0 million in expenses related to CSL and board members for the nine months ended September 30, 2017 and 2016, respectively. The Company incurred approximately $1.0 million and $0.0 million in expenses related to CSL and board members for the three months ended September 30, 2017 and 2016, respectively. As of September 30, 2017, the Company has accrued $0.2 million to CSL and board members and at December 31, 2016 amounts due to CSL and board members were negligible.

Acquisition

In January 2017, Ranger Services, through its wholly owned subsidiary, entered into a purchase agreement (the “Allied Purchase Agreement”) with Allied Energy Real Estate, LLC (“Allied Energy”). CSL, which employs certain members of the Company’s board holds a majority of the voting power of the Company’s common stock and is an indirect owner of Allied Energy. Pursuant to the Allied Purchase Agreement, Ranger Services purchased certain real property in Milliken, Colorado from Allied Energy for a purchase price of $4.0 million.

Related Party Debt

In February 2017, Ranger entered into loan agreements (Collectively the “Ranger Bridge Loan”) with each of CSL Energy Opportunities II L.P. (“CSL Opportunities II”), CSL Energy Holdings II LLC (“CSL Holdings II”) and Bayou Holdings (together with CSL Holdings II and CSL Energy Opportunities II, the “the Bridge Loan Lenders”) each an indirect equity owner of Ranger Services. The Ranger Bridge Loan, which was obtained to fund capital expenditures and working capital, was evidenced by promissory notes payable to the Bridge Loan Lenders in an aggregate principal amount of $11.1 million, consisting of three individual promissory notes in the principal amounts of (i) $4.4 million payable to CSL Opportunities II, (ii) $3.2 million payable to CSL Holdings II and (iii) $3.6 million payable to Bayou Holdings. The note was secured by substantially all of the Company’s assets (approximately $132.1 million of the Company’s total assets as of September 30, 2017). Each note bore interest at a rate of 15% and matured upon the earlier of February 21, 2018 or ten days after the consummation of an initial public offering. The loan agreement included a make‑whole provision in which the Company would pay 125% of the total amount advanced to the Company upon settlement. The 125% is inclusive of the 15% interest rate. As of June 30, 2017, there was $17.1 million outstanding on the Ranger Bridge Loan. During April 2017, the Company increased its bridge loan debt by $1.0 million to $12.1 million to fund capital expenditures and working capital. During May 2017, the Company increased its bridge loan debt by $2.5 million and then again by another $2.5 million in June to $17.1 million to fund capital expenditures and working capital. In July 2017, the Company increased its bridge loan debt by $3.9 million to $21.0 million.

In connection with the corporate reorganization August 16, 2017, all of the Ranger Bridge Loan was converted to equity. For more information about the corporate reorganization please see Note 1.

Tax Receivable Agreement

On August 16, 2017, in connection with the Offering, the Company entered into a Tax Receivable Agreement (the “Tax Receivable Agreement”) with certain of the existing Ranger Unit holders and their permitted transferees (each

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such person, a “TRA Holder” and together, the “TRA Holders”). The Tax Receivable Agreement generally provides for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax that the Company actually realizes (computed using simplifying assumptions to address the impact of state and local taxes) or is deemed to realize in certain circumstances in periods after the Offering as a result of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Ranger Units in connection with the Offering or pursuant to the exercise of the Redemption Right or the Call Right (each as defined in the Amended and Restated Limited Liability Company Agreement of Ranger LLC) and (ii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the Tax Receivable Agreement. The Company will retain the benefit of the remaining 15% of these cash savings. The term of the Tax Receivable Agreement commences on August 16, 2017 and will continue until all tax benefits that are subject to the Tax Receivable Agreement (or the Tax Receivable Agreement is terminated due to other circumstances, including the Company’s breach of a material obligation thereunder or certain mergers, assets sales, other forms of business combination or other changes of control) have been utilized or expired, unless the Company exercises its right to terminate the Tax Receivable Agreement. The payments under the Tax Receivable Agreement will not be conditioned upon a TRA Holder having a continued ownership interest in either Ranger LLC or the Company.

If the Company elects to terminate the Tax Receivable Agreement early or the Tax Receivable Agreement is terminated due to other circumstances (including the Company’s breach of a material obligation thereunder or certain mergers, asset sales other forms of business combinations or other changes of control), its obligations under the Tax Receivable Agreement would accelerate and it would be required to make an immediate payment equal to the present value of the anticipated future tax payments to be made by Ranger under the Tax Receivable Agreement (determined by applying a discount rate of one-year LIBOR plus 150 basis points and based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement). In addition, payments due under the Tax Receivable Agreement will be similarly accelerated following certain mergers or other changes of control.

Registration Rights Agreement

On August 16, 2017, in connection with the closing of the Offering, the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with certain stockholders (the “Holders”).

Pursuant to, and subject to the limitations set forth in, the Registration Rights Agreement, at any time after the 180-day lock-up period described in the Final Prospectus, the Holders have the right to require the Company by written notice to prepare and file a registration statement registering the offer and sale of a number of their shares of Class A Common Stock. Reasonably in advance of the filing of any such registration statement, the Company is required to provide notice of the request to all other Holders who may participate in the registration. The Company is required to use all commercially reasonable efforts to maintain the effectiveness of any such registration statement until all shares covered by such registration statement have been sold. Subject to certain exceptions, the Company is not obligated to effect such a registration within 90 days after the closing of any underwritten offering of shares of Class A Common Stock requested by the Holders pursuant to the Registration Rights Agreements. The Company is also not obligated to effect any registration where such registration has been requested by the holders of Registrable Securities (as defined in the Registration Rights Agreement) which represent less than $25 million, based on the five-day volume weighted average trading price of the Class A Common Stock on the New York Stock Exchange.

In addition, pursuant to the Registration Rights Agreement, the Holders have the right to require the Company, subject to certain limitations set forth therein, to effect a distribution of any or all of their shares of Class A Common Stock by means of an underwritten offering. Further, subject to certain exceptions, if at any time the Company proposes to register an offering of its equity securities or conduct an underwritten offering, whether or not for its account, then the Company must notify the Holders of such proposal at least three business days before the anticipated filing date or commencement of the underwritten offering, as applicable, to allow them to include a specified number of their shares in that registration statement or underwritten offering, as applicable.

These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration or offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. The Company will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective.

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The obligations to register shares under the Registration Rights Agreement will terminate as to any Holder when the Registrable Securities held by such Holder are no longer subject to any restrictions on trading under the provisions of Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”), including any volume or manner of sale restrictions. Registrable Securities means all shares of Class A Common Stock owned at any particular point in time by a Holder other than shares (i) sold pursuant to an effective registration statement under the Securities Act, (ii) sold in a transaction pursuant to Rule 144 under the Securities Act, (iii) that have ceased to be outstanding or (iv) that are eligible for resale without restriction and without the need for current public information pursuant to any section of Rule 144 under the Securities Act.

NOTE 17. SEGMENT REPORTING

The Company’s operations are all located in the United States and organized into two reportable segments: Well Services and Processing Solutions. Our reportable segments comprise the structure used by our Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance during the years presented in the accompanying condensed consolidated financial statements. Our CODM evaluates the segments’ operating performance based on multiple measures including Adjusted EBITDA, rig hours and rig utilization. The following is a description of the segments:

Well Services. The Company’s well service rigs facilitate operations throughout the lifecycle of a well, including (i) well completion support; (ii) workover; (iii) well maintenance; and (iv) decommissioning. We provide these advanced well services to Exploration & Production (“E&P”) companies, particularly to those operating in unconventional oil and natural gas reservoirs and requiring technically and operationally advanced services. Our well service rigs are designed to support growing U.S. horizontal well demands. In addition to our core well service rig operations, we offer a suite of complementary services, including wireline, snubbing, fluid management and well service-related equipment rentals.

Processing Solutions. The Company provides a range of proprietary, modular equipment for the processing of rich natural gas streams at the wellhead or central gathering points in basins where drilling and completion activity has outpaced the development of permanent processing infrastructure.

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Segment information as of September 30, 2017 and December 31, 2016 and for the three and nine months ended September 30, 2017 and 2016 is as follows (in millions):


			Processing
	Well Services		Solutions		Total
	Three months ended September 30, 2017
Revenues	$	39.0	$	2.1	$	41.1
Operating income (loss)		(5.2)		0.4		(4.8)
Interest expense, net		(4.3)		—		(4.3)

	Nine months ended September 30, 2017
Revenues	$	97.9	$	5.9	$	103.8
Operating income (loss)		(16.0)		0.8		(15.2)
Interest expense, net		(5.8)		(0.1)		(5.9)
	As of September 30, 2017
Total assets	$	229.3	$	27.7	$	257.0


			Processing
	Well Services		Solutions		Total
	Three months ended September 30, 2016
Revenues	$	14.2	$	1.9	$	16.1
Operating income		0.1		0.2		0.3
Interest expense, net		(0.1)		-		(0.1)

	Nine months ended September 30, 2016
Revenues	$	22.0	$	4.5	$	26.5
Operating loss		(1.0)		(0.6)		(1.6)
Interest expense, net		(0.2)		(0.1)		(0.3)
	As of December 31, 2016
Total assets	$	107.9	$	27.8	$	135.7

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the historical financial statements and related notes included in Part I, Item 1 of this report. This discussion contains “forward‑looking statements” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward‑looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report. Please read Cautionary Note Regarding Forward‑Looking Statements. Also, please read the risk factors and other cautionary statements described under “Item 1A.-Risk Factors” included elsewhere in this report. We assume no obligation to update any of these forward‑looking statements.

Overview

We are one of the largest independent providers of high‑spec well service rigs and associated services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. We believe that our fleet of 129 well service rigs (including 49 well service rigs we acquired on August 16, 2017 in the ESCO Acquisition) is among the newest and most advanced in the industry and, based on our historical rig utilization and feedback from our customers, we believe that we are an operator of choice for U.S. onshore Exploration and Production (“E&P”) companies that require completion and production services at increasing lateral lengths. Our high‑spec well service rigs facilitate operations throughout the lifecycle of a well, including (i) well completion support, such as milling out composite plugs used during hydraulic fracturing; (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components; and (iv) decommissioning, such as plugging and abandonment operations. In addition to our core well service rig operations, we offer a suite of complementary services, including wireline, snubbing, fluid management and well service-related equipment rentals. We also provide rental equipment, including well control packages, hydraulic catwalks and other equipment that are often deployed with our well service rigs. In addition, we own and operate a fleet of proprietary, modular natural gas processing equipment that processes rich natural gas streams at the wellhead or central gathering points. We have operations in most of the active oil and natural gas basins in the United States, including the Permian Basin, the Denver‑Julesburg Basin, the Bakken Shale, the Eagle Ford Shale, the Haynesville Shale, the Gulf Coast and the SCOOP and STACK plays.

Our Predecessor and Ranger Energy Services, Inc.

Ranger Energy Services, Inc. (“Ranger Inc.” or “the Company”) was formed on February 17, 2017, and did not conduct any material business operations prior to the transactions described under “Initial Public Offering” other than certain activities related to the initial public offering (the “Offering”). Our Predecessor consists of Ranger Services and Torrent Services on a combined consolidated basis. In connection with the transactions described Note 1 – Organization and Business Operations – Reorganization, the Existing Owners contributed the equity interests in the Predecessor Companies to us in exchange for shares of our Class A Common Stock, Ranger Units and shares of our Class B common stock.

Ranger Inc. was, through Ranger Holdings, formed by CSL in June 2014 as a provider of high‑spec well service rigs and associated services. Torrent Services was, through Torrent Holdings, acquired by CSL in September 2014 as a provider of proprietary, modular equipment for the processing of natural gas. In June 2016, CSL indirectly acquired substantially all of the assets of Magna, a provider of well services and wireline services, which it contributed to Ranger Services in September 2016. In October 2016, Ranger Services acquired substantially all of the assets of Bayou, an owner and operator of high‑spec well service rigs. The historical condensed consolidated financial information included in this report presents (i) prior to August 16, 2017, the historical financial information of the Predecessor Companies, including, as applicable, the results of operations of Magna and Bayou for periods subsequent to their respective acquisitions and (ii) subsequent to August 16, 2017 the historical financial information of the Company. The historical condensed consolidated financial information of our Predecessor is not indicative of the results that may be expected in any future periods. For more information, please see the historical condensed consolidated related notes thereto included elsewhere in this quarterly report.

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On August 16, 2017, the Company acquired 49 high-spec well service rigs, certain ancillary equipment, and certain of its liabilities. ESCO is included in our consolidated financial results from the date of acquisition onward.

We conduct our operations through two segments: Well Services and Processing Solutions. Our Well Services segment has historically consisted of the results of operations of Ranger Services and, as applicable, Magna, Bayou and the ESCO Acquisition assets from their respective acquisition dates, while our Processing Solutions segment has historically consisted of the results of operations of Torrent Services. Our Well Services segment provides high‑spec well service rigs and complementary equipment and services in the United States, with a focus on technically demanding unconventional horizontal well completion, workover and maintenance operations. These services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well. Our Processing Solutions segment engages in the rental, installation, commissioning, start‑up, operation and maintenance of MRUs, NGL stabilizer units, NGL storage units and related equipment. We operate in most of the active oil and natural gas basins in the United States, including the Permian Basin, the Denver‑Julesburg Basin, the Bakken Shale, the Eagle Ford Shale, the Haynesville Shale, the Gulf Coast and the SCOOP and STACK plays. For additional information about our assets and operations, please see Note 17 - Segment Reporting to the unaudited interim condensed consolidated financial statements.

Initial Public Offering

On August 16, 2017, Ranger completed the Offering of 5,862,069 shares of its Class A Common Stock. The gross proceeds of the Offering, based on a public offering price of $14.50 per share, was $85.0 million, which resulted in net proceeds to Ranger of $80.8 million, after deducting $4.2 million of underwriting discounts and commissions. Ranger received net proceeds of approximately $20.7 million after the Company paid off the remainder of our long term debt of $10.4 million, funded $45.2 million for the cash portion of the ESCO Acquisition, $3.8 million of costs incurred due to the Offering, and $0.7 million for cash bonuses to certain employees.

How We Generate Revenues

We currently generate revenues through the provision of a variety of oilfield services. These services are performed under a variety of contract structures, including a long term take‑or‑pay contract and various master service agreements, as supplemented by statements of work, pricing agreements and specific quotes. A portion of our master services agreements include provisions that establish pricing arrangements for a period of up to one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer.

We recognize revenue in our Well Services segment when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. We price well servicing by the hour or by the day when services are performed. Well servicing is sold without warranty or right of return.

We recognize revenue in our Processing Solutions segment when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Revenues from equipment leasing, operations and maintenance services are recognized as earned. These services are sold without warranty or right of return.

Costs of Conducting Our Business

The principal expenses involved in conducting our business are personnel, repairs and maintenance costs, general and administrative, depreciation and amortization and interest expense. We manage the level of our expenses, except depreciation and amortization and interest expense, based on several factors, including industry conditions and expected demand for our services. In addition, a significant portion of the costs we incur in our business is variable based on the quantities of specific services provided and the requirements of such services.

Direct cost of services and general and administrative expenses include the following major cost categories: personnel costs and equipment costs (including repair and maintenance).

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Personnel costs associated with our operational employees represent a significant cost of our business. A substantial portion of our labor costs is attributable to our crews and is partly variable based on the requirements of specific customers and operations. A key component of personnel costs relates to the ongoing training of our employees, which improves safety rates and reduces attrition. We also incur costs to employ personnel to support our services and perform maintenance on our assets. Costs for these employees are not directly tied to our level of business activity.

We incur significant equipment costs in connection with the operation of our business, including repair and maintenance costs.

How We Evaluate Our Operations

Our management intends to use a variety of metrics to analyze our operating results and profitability. These metrics include, among others, the following:

Revenues;

Operating Income (Loss); and

Adjusted EBITDA.

In addition, within our Well Services segment, our management intends to use additional metrics to analyze our activity levels and profitability. These metrics include, among others, the following:

Rig Hours; and

Rig Utilization.

Revenues

We analyze our revenues by comparing actual revenues to our internal projections for a given period and to prior periods to assess our performance. We believe that revenues are a meaningful indicator of the demand and pricing for our services.

Operating Income (Loss)

We analyze our operating income (loss), which we define as revenues less cost of services, general and administrative expenses, depreciation and amortization, impairment and other operating expenses, to measure our financial performance. We believe operating income (loss) is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income (loss) to our internal projections for a given period and to prior periods.

Adjusted EBITDA

We view Adjusted EBITDA, which is a non‑GAAP financial measure, as an important indicator of performance. We define Adjusted EBITDA as net loss before interest expense, net, income tax provision (benefit), depreciation and amortization, equity‑based compensation, acquisition‑related and severance costs, impairment of goodwill and other non‑cash and certain other items that we do not view as indicative of our ongoing performance. See “-Results of Operations—Note Regarding Non‑GAAP Financial Measure” for more information and reconciliations of net income (loss) to Adjusted EBITDA, the most directly comparable financial measure calculated and presented in accordance with GAAP.

Rig Hours

Within our Well Services segment, we analyze rig hours as an important indicator of our activity levels and profitability. Rig hours represent the aggregate number of hours that our well service rigs actively worked during the periods presented. We typically bill customers for our well services on an hourly basis during the period that a well service rig is actively working, making rig hours a useful metric for evaluating our profitability.

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Rig Utilization

Within our Well Services segment, we analyze rig utilization as a further important indicator of our activity levels and profitability. We measure rig utilization by reference to average monthly hours per rig, which is calculated by dividing (a) the approximate, aggregate operating well service rig hours for the periods presented by (b) the aggregate number of well service rigs in our fleet during such period, as aggregated on a monthly basis utilizing a mid-month convention whereby a well service rig added to our fleet during a month, meaning that we have taken delivery of such well service rig, is assumed to be in our fleet for one half of such month. We believe that rig utilization as measured by average monthly hours per well service rig is a meaningful indicator of the operational efficiency of our core revenue-producing assets, market demand for our well services and our ability to profitably capitalize on such demand. Our evaluation of our rig utilization as measured by average monthly hours per rig may not be comparable to that of our competitors. For example, our competitors’ well service rig fleets are typically comprised primarily of older, lower spec well service rigs that are not as well suited to servicing modern horizontal well designs as are high-spec well service rigs, which may result in lower average rig hours per rig for our competitors’ fleets as compared to our fleet.

The primary factors that have historically impacted, and will likely continue to impact, our actual aggregate well service rig hours for any specified period are (i) customer demand, which is influenced by factors such as commodity prices, the complexity of well completion operations and technological advances in our industry, and (ii) our ability to meet such demand, which is influenced by changes in our fleet size and resulting rig availability, as well as weather, employee availability and related factors. The primary factors that have historically impacted, and will likely continue to impact, the aggregate number of well service rigs in our fleet during any specified period are the extent and timing of changes in the size of our well service rig fleet to meet short-term and expected long-term demand, and our ability to successfully maintain a fleet capable of ensuring sufficient, but not excess, rig availability to meet such demand.

For the nine months ending September 30, 2017 and 2016, our rig utilization as measured by average monthly hours per rig was approximately 196 and 148, respectively. Actual aggregate operating well service rig hours increased from approximately 30,000 for the nine months ended September 30, 2016 to approximately 137,500 during the nine months ended September 30, 2017, primarily as a result of our acquisitions of ESCO, Magna, Bayou, and their associated well service rigs as well as newly acquired service rigs. The related increase in rig utilization resulted from an increase in the average number of well service rigs in our active fleet from 23 during the nine months ended September 30, 2016 to 78 during the nine months ended September 30, 2017, and a corresponding increase in our potential aggregate well service rig hours.

For the three months ended September 30, 2017 and 2016, our rig utilization as measured by average monthly hours per rig was approximately 199 and 141, respectively. Actual aggregate operating well service rig hours increased from approximately 13,000 in the three months ended September 30, 2016 to approximately 59,000 in the three months ended September 30, 2017. The related increase in rig utilization resulted from an increase in the average number of well service rigs in our active fleet from 31 during the three months ended September 30, 2016 to 100 during the three months ended September 30, 2017, and a corresponding increase in our potential aggregate well service rig hours.

Factors Impacting the Comparability of Results of Operations

Magna and Bayou Acquisitions

Our Predecessor’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2017 and 2016 include the results of operations for Magna and Bayou from their respective acquisition dates during 2016. As a result, our Predecessor’s historical financial data does not give an accurate indication of what our actual results would have been if such acquisitions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

ESCO Acquisition

Our Predecessor’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2017 and 2016 do not include the results of operations for the assets we acquired in the ESCO Acquisition , other than for the period from August 16, 2017 to September 30, 2017. As a result, our Predecessor’s historical financial data do not give you an accurate indication of what our actual results would have been if the ESCO

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Acquisition had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

Public Company Costs

We expect to incur incremental, non‑recurring costs related to our transition to a publicly traded and taxable corporation, including the costs of the Offering and the costs associated with the initial implementation of our Sarbanes‑Oxley Section 404 internal control implementation. We also expect to incur additional significant and recurring expenses as a publicly traded corporation, including costs associated with the employment of additional personnel, compliance under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), annual and quarterly reports to common shareholders, registrar and transfer agent fees, national stock exchange fees, audit fees, Sarbanes-Oxley Section 404 internal testing, incremental director and officer liability insurance costs and director and officer compensation.

Reorganization

On August 10, 2017, we entered into a Master Reorganization Agreement (the “Master Reorganization Agreement”) with, among others, Ranger LLC, Ranger Holdings, Ranger Energy Holdings II, LLC, a Delaware limited liability company (“Ranger Holdings II”), Torrent Holdings, and Torrent Energy Holdings II, LLC, a Delaware limited liability company (“Torrent Holdings II” and, together with Ranger Holdings, Ranger Holdings II and Torrent Holdings, the “Existing Owners”).

(i) Ranger Holdings II and Torrent Holdings II contributed certain of the equity interests in Ranger Services, and Torrent Services, respectively, to the Company in exchange for an aggregate of 1,638,386 shares of Class A Common Stock and an aggregate of $3.0 million to be paid to CSL Energy Holdings I, LLC, a Delaware limited liability company, and CSL Energy Holdings II, LLC, a Delaware limited liability company, on or prior to the 18-month anniversary of the consummation of the Offering in, at the Company’s option, cash, shares of Class A Common Stock (with such shares to be valued based on the greater of the initial public offering price of the Class A Common Stock in the Offering and a 30-day volume-weighted average price) or a combination thereof, and the Company contributed such equity interests to Ranger LLC in exchange for 1,638,386 Ranger Units;

(ii) Ranger Holdings and Torrent Holdings contributed the remaining membership interests in the Predecessor Companies to Ranger LLC in exchange for 5,621,491 units in Ranger Units and 5,621,491 shares of the Company’s Class B common stock, which the Company issued and contributed to Ranger LLC;

(iii) the Company contributed all of the net proceeds received by it in the Offering to Ranger LLC in exchange for 5,862,069 Ranger Units;

(iv) Ranger LLC distributed to each of Ranger Holdings and Torrent Holdings one share of Class B Common Stock received pursuant to (ii) above for each Ranger Unit such Existing Owner holds; and

(v) as consideration for the termination of certain loan agreements, the Company will issue 567,895 shares of Class A Common Stock (in connection with which Ranger LLC issued 567,895 Ranger Units to the Company) and Ranger LLC issued an aggregate of 1,244,663 Ranger Units (and distribute a corresponding number of shares of Class B Common Stock) to the lenders thereof.

The foregoing transactions were be undertaken in reliance on an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereof. As a result of these transactions, Ranger LLC became a subsidiary of the Company and the Predecessor Companies became wholly owned subsidiaries of Ranger LLC.

In connection with the Offering, we entered into a Tax Receivable Agreement (the "Tax Receivable Agreement") with certain of the Ranger Unit Holders and their permitted transferees (each such person, a "TRA Holder"

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and, together, the "TRA Holders"). The Tax Receivable Agreement generally provides for the payment by us to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax that we actually realize (computed using the estimated impact of state and local taxes) or are deemed to realize in certain circumstances in periods following the Offering as a result of (i) certain increases in tax basis that occur as a result of our acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder's Ranger Units in connection with this offering or pursuant to the exercise of the Redemption Right or the Call Right (each as defined in the Amended and Restated Limited Liability Company Agreement of Ranger LLC) and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings.

Income Taxes

Ranger Inc. is a Subchapter C corporation under the Internal Revenue Code of 1986, as amended (the “Code”), and, as a result, will be subject to U.S. federal, state and local income taxes. Although the Predecessor Companies are subject to franchise tax in the State of Texas (at less than 1% of modified pre‑tax earnings), they have historically passed through their taxable income to their owners for U.S. federal and other state and local income tax purposes and thus were not subject to U.S. federal income taxes or other state or local income taxes. Accordingly, the financial data attributable to our Predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality other than franchise tax in the State of Texas. We account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled pursuant to the provisions of Accounting Standards Codification (“ASC”) 740, Income Taxes. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

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Results of Operations

Three Months Ended September 30, 2016 compared to Three Months Ended September 30, 2017

The following table sets forth our Predecessor’s selected operating data for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016.


	Three Months Ended
	September 30,				Change
	2017		2016		$		%
Revenues:
Well Services	$	39.0	$	14.2	$	24.8	175	%
Processing Solutions		2.1		1.9		0.2	11
Total revenues		41.1		16.1		25.0	155
Operating expenses:
Cost of services (exclusive of depreciation and amortization shown separately):
Well Services		33.1		11.0		22.1	201
Processing Solutions		0.8		0.7		0.1	14
Total cost of services		33.9		11.7		22.2	190
General and administrative		7.9		2.7		5.2	193
Depreciation and amortization		4.1		1.4		2.7	193
Total operating expenses		45.9		15.8		30.1	191
Operating income (loss)		(4.8)		0.3		(5.1)	(1,700)
Other expenses
Interest expense, net		(4.3)		(0.1)		(4.2)	4,200
Total other expenses		(4.3)		(0.1)		(4.2)	4,200
Loss before income tax expense		(9.1)		0.2		(9.3)	(4,650)
Tax expense		(0.4)		—		(0.4)	—
Net income (loss)	$	(9.5)	$	0.2	$	(9.7)	(4,850)	%

Revenues. Revenues for the three months ended September 30, 2017 increased $25.0 million, or 155%, to $41.1 million from $16.1 million for the three months ended September 30, 2016. The increase in revenues by segment was as follows:

Well Services. Well Services revenues for the three months ended September 30, 2017 increased $24.8 million, or 175%, to $39.0 million from $14.2 million for the three months ended September 30, 2016. The increase was primarily due to an increased number of rigs, to an average of 99 rigs from an average of 31 rigs, providing workover rig services, which accounted for $11.8 million, or 48% of the segment increase. Approximately $4.3 million of the increase in workover rig services was due to the ESCO Acquisition. The increase in workover rig services included a 351% increase in total rig hours to 59,000 from 13,000 for the three months ended September 30, 2017 compared to the three months ended September 30, 2016.

Processing Solutions. Processing Solutions revenues for the three months ended September 30, 2017 increased $0.2 million, or 11%, to $2.1 million from $1.9 million for the three months ended September 30, 2016. The increase was primarily attributable to an increase in MRU revenue due to an additional 4 units, increased MRU utilization and an increase in our rental rates.

Cost of services (excluding depreciation and amortization shown separately). Cost of services for the three months ended September 30, 2017 increased $22.2 million, or 190%, to $33.9 million from $11.7 million for the three months ended September 30, 2016. As a percentage of revenue, cost of services was 82% and 73% for the three months ended September 30, 2017 and 2016, respectively. The increase in cost of services by segment was as follows:

Well Services. Well Services cost of services for the three months ended September 30, 2017 increased $22.1 million, or 201%, to $33.1 million from $11.0 million for the three months ended September 30, 2016. The

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increase was primarily attributable to an increase in expenses due to the expansion of the Company’s activities; notably employee costs, and repair and maintenance costs.

Processing Solutions. Processing Solutions cost of services for the three months ended September 30, 2017 increased $0.1 million, or 14%, to $0.8 million from $0.7 million for the three months ended September 30, 2016. The increase was primarily attributable to increases in mobilization costs incurred which corresponds with additional revenues.

General & Administrative. General and administrative expenses for the three months ended September 30, 2017 increased $5.2 million, or 193%, to $7.9 million from $2.7 million for the three months ended September 30, 2016. The increase in general and administrative expenses by segment was as follows:

Well Services. Well Services general and administrative expenses for the three months ended September 30, 2017 increased $5.3 million, or 279%, to $7.2 million from $1.9 million for the three months ended September 30, 2016. The increase was primarily attributable to an increase in expenses due to the expansion of the Company’s activities; notably expenses for payroll costs (including severance costs), professional, office costs, costs associated with the Offering, and equity‑based compensation expense.

Processing Solutions. Processing Solutions general and administrative expenses for the three months ended September 30, 2017 decreased $0.1 million, or 13%, to $0.7 million from $0.8 million for the three months ended September 30, 2016.

Depreciation and Amortization. Depreciation and amortization for the three months ended September 30, 2017 increased $2.7 million, or 193%, to $4.1 million from $1.4 million for the three months ended September 30, 2016. The increase in depreciation and amortization expense by segment was as follows:

Well Services. Well Services depreciation and amortization expense for the three months ended September 30, 2017 increased $2.6 million, or 217%, to $3.8 million from $1.2 million for the three months ended September 30, 2016. The increase was primarily attributable to fixed assets that were put in place during 2016 and the nine months ended September 30, 2017, due to the acquisitions of ESCO, Magna, and Bayou as well as additional fixed asset purchases by Ranger Services.

Processing Solutions. Processing Solutions depreciation and amortization expense was $0.3 million for the three months ended September 30, 2017 compared to $0.2 million for the three months ended September 30, 2016.

Interest Expense, net. Interest expense, net for the three months ended September 30, 2017 increased $4.2 million, or 4,200%, to $4.3 million from $0.1 million for the three months ended September 30, 2016. The increase to interest expense, net by segment was as follows:

Well Services. Well Services interest expense, net for the three months ended September 30, 2017 increased $4.2 million, or 4,200%, to $4.3 million from $0.1 million for the three months ended September 30, 2016. The increase to interest expense, net was attributable to an increase in average borrowing as well as the payment of the make‑whole in connection with repaying and retiring the related party loans during the three months ended September 30, 2017 compared to the three months ended September 30, 2016.

Processing Solutions. Processing Solutions interest expense, net was less than $0.1 million for the three months ended September 30, 2017 and 2016.

Other. During the three months ended September 30, 2017 revenues were negatively impacted by (i) Hurricane Harvey which resulted in a loss of revenue and (ii) as part of the ESCO Acquisition integration, six rigs were transitioned out of service in order to bring the crews up to the Company’s standards. Also during the three months ended September 30, 2017 there were start up operational and administrative costs included in our Well Services business incurred for the Permian Basin and wireline rig operations. In addition, the delivery of new rigs was further delayed due to Hurricane Harvey.

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Nine months Ended September 30, 2016 compared to Nine months Ended September 30, 2017

The following table sets forth our Predecessor’s selected operating data for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016.


	Nine Months Ended
	September 30,				Change
	2017		2016		$		%
Revenues:
Well Services	$	97.9	$	22.0	$	75.9	345	%
Processing Solutions		5.9		4.5		1.4	31
Total revenues		103.8		26.5		77.3	292
Operating expenses:
Cost of services (exclusive of depreciation and amortization shown separately):
Well Services		81.1		17.1		64.0	374
Processing Solutions		2.2		1.8		0.4	22
Total cost of services		83.3		18.9		64.4	341
General and administrative		24.0		6.1		17.9	293
Depreciation and amortization		11.7		3.1		8.6	277
Total operating expenses		119.0		28.1		90.9	323
Operating loss		(15.2)		(1.6)		(13.6)	(850)
Other expenses
Interest expense, net		(5.9)		(0.3)		(5.6)	(1,867)
Total other expenses		(5.9)		(0.3)		(5.6)	(1,867)
Loss before income tax expense		(21.1)		(1.9)		(19.2)	(1,011)
Tax expense		(0.4)		—		(0.4)	—
Net loss	$	(21.5)	$	(1.9)	$	(19.6)	(1,032)	%

Revenues. Revenues for the nine months ended September 30, 2017 increased $77.3 million, or 292%, to $103.8 million from $26.5 million for the nine months ended September 30, 2016. The increase in revenues by segment was as follows:

Well Services. Well Services revenues for the nine months ended September 30, 2017 increased $75.9 million, or 345%, to $97.9 million from $22.0 million for the nine months ended September 30, 2016. Approximately $4.3 million of the increase in workover rig services was due to the ESCO Acquisition. The increase was primarily due to increased number of rigs, to an average of 78 from an average of 23 Rigs, providing workover rig services, which accounted for $42.7 million, or 56% of the segment increase. The increase in workover rig services included a 358% increase in total rig hours to 137,500 from 30,000 for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.

Processing Solutions. Processing Solutions revenues for the nine months ended September 30, 2017 increased $1.4 million, or 31%, to $5.9 million from $4.5 million for the nine months ended September 30, 2016. The increase was primarily attributable to an increase in MRU revenue of $1.0 million due to an increase in the number of MRUs we owned and an additional $0.3 million in tank rental revenue.

Cost of services (excluding depreciation and amortization shown separately). Cost of services for the nine months ended September 30, 2017 increased $64.4 million, or 341%, to $83.3 million from $18.9 million for the nine months ended September 30, 2016. As a percentage of revenue, cost of services was 80% and 71% for the nine months ended September 30, 2017 and 2016, respectively. The increase in cost of services by segment was as follows:

Well Services. Well Services cost of services for the nine months ended September 30, 2017 increased $64.0 million, or 374%, to $81.1 million from $17.1 million for the nine months ended September 30, 2016. The increase was primarily attributable to an increase in expenses due to the expansion of the Company’s activities; notably employee costs, and repair and maintenance costs.

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Processing Solutions. Processing Solutions cost of services for the nine months ended September 30, 2017 increased $0.4 million, or 22%, to $2.2 million from $1.8 million for the nine months ended September 30, 2016. The increase was primarily attributable to increases in mobilization costs incurred which corresponds with additional revenues.

General & Administrative. General and administrative expenses for the nine months ended September 30, 2017 increased $17.9 million, or 293%, to $24.0 million from $6.1 million for the nine months ended September 30, 2016. The increase in general and administrative expenses by segment was as follows:

Well Services. Well Services general and administrative expenses for the nine months ended September 30, 2017 increased $18.4 million, or 526%, to $21.9 million from $3.5 million for the nine months ended September 30, 2016. The increase was primarily attributable to an increase in expenses due to the expansion of the Company’s activities; notably expenses for payroll, office costs, and professional fees more specifically costs related to the Offering, the ESCO Acquisition and the restructuring transactions in connection with the Offering.

Processing Solutions. Processing Solutions general and administrative expenses for the nine months ended September 30, 2017 decreased $0.5 million, or 19%, to $2.1 million from $2.6 million for the nine months ended September 30, 2016. The decrease was primarily attributable to lower bad debt expense as well as lower payroll and professional fees.

Depreciation and Amortization. Depreciation and amortization for the nine months ended September 30, 2017 increased $8.6 million, or 277%, to $11.7 million from $3.1 million for the nine months ended September 30, 2016. The increase in depreciation and amortization expense by segment was as follows:

Well Services. Well Services depreciation and amortization expense for the nine months ended September 30, 2017 increased $8.4 million, or 336%, to $10.9 million from $2.5 million for the nine months ended September 30, 2016. The increase was primarily attributable to fixed assets that were put in place during 2016 and the nine months ended September 30, 2017, due to the acquisitions of ESCO, Magna, and Bayou as well as additional fixed asset purchased by Ranger Services.

Processing Solutions. Processing Solutions depreciation and amortization expense was $0.8 million for the nine months ended September 30, 2017 compared to $0.6 million for the nine months ended September 30, 2016.

Interest Expense, net. Interest expense, net for the nine months ended September 30, 2017 increased $5.6 million, or 1,876%, to $5.9 million from $0.3 million for the nine months ended September 30, 2016. The increase to interest expense, net by segment was as follows:

Well Services. Well Services interest expense, net for the nine months ended September 30, 2017 increased $5.5 million, or 1,833%, to $5.8 million from $0.3 million for the nine months ended September 30, 2016. The increase to interest expense, net was attributable to an increase in average borrowing as well as the make‑whole provision in the related party loans paid during the nine months ended September 30, 2017.

Processing Solutions. Processing Solutions interest expense, net was less than $0.1 million for the nine months ended September 30, 2017 compared to $0.1 million for the nine months ended September 30, 2016.

Other. During the nine months ended September 30, 2017 revenues were negatively impacted by (i) Hurricane Harvey which resulted in a loss of revenue and (ii) as part of the ESCO Acquisition integration, six rigs were transitioned out of service in order to bring the crews up to the Company’s standards. Also during the nine months ended September 30, 2017 there were start up operational and administrative costs included in our Well Services business incurred for the Permian Basin and wireline rig operations. In addition, the delivery of new rigs was further delayed due to Hurricane Harvey.

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Note Regarding Non‑GAAP Financial Measure

Adjusted EBITDA is not a financial measure determined in accordance with GAAP. We define Adjusted EBITDA as net income (loss) before interest expense, net, income tax provision (benefit), depreciation and amortization, equity‑based compensation, acquisition‑related and severance costs, impairment of goodwill, costs incurred for offering-related and certain other items that we do not view as indicative of our ongoing performance.

We believe Adjusted EBITDA is a useful performance measure because it allows for an effective evaluation of our operating performance when compared to our peers, without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net loss determined in accordance with GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an indication that our results will be unaffected by the items excluded from Adjusted EBITDA. Our computations of Adjusted EBITDA may not be identical to other similarly titled measures of other companies. The following table presents reconciliations of net income (loss) to Adjusted EBITDA, our most directly comparable financial measure calculated and presented in accordance with GAAP.


	Three Months Ended						Three Months Ended
	September 30, 2017						September 30, 2016						Change $
	Well		Processing				Well		Processing				Well		Processing
	Services		Solutions		Total		Services		Solutions		Total		Services		Solutions		Total
Net income (loss)	$	(9.9)	$	0.4	$	(9.5)	$	0.1	$	0.1	$	0.2	$	(10.0)	$	0.3	$	(9.7)
Interest expense, net		4.3		—		4.3		0.1		—		0.1		4.2		—		4.2
Tax expense		0.4		—		0.4		—		—		—		0.4		—		0.4
Depreciation and amortization		3.8		0.3		4.1		1.2		0.2		1.4		2.6		0.1		2.7
Equity based compensation		0.1		0.1		0.2		—		—		—		0.1		0.1		0.2
Acquisition related and severance costs		2.2		—		2.2		—		—		—		2.2		—		2.2
Costs incurred for offering related services		1.3		—		1.3		—		—		—		1.3		—		1.3
Adjusted EBITDA	$	2.2	$	0.8	$	3.0	$	1.4	$	0.3	$	1.7	$	0.8	$	0.5	$	1.3

Adjusted EBITDA for the three months ended September 30, 2017 increased $1.3 million to $3.0 million from $1.7 million for the three months ended September 30, 2016. The increase by segment was as follows:

Well Services. Well Services Adjusted EBITDA increased $0.8 million to $2.2 million from $1.4 million due mainly to significant increase revenues of $24.8 million offset by a corresponding increase in cost of services of $22.1 million as well as an increase in general and administrative expenses of $5.3 million net of equity based compensation of $0.1 million, an increase in the tax provision of $0.4 million, acquisition related and severance costs of $2.2 million, and costs incurred for offering related services of $1.3 million.

Processing Solutions. Processing Solutions Adjusted EBITDA increased $0.5 million to $0.8 million from $0.3 million due primarily to an increase in net income (loss) of $0.3 million.

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	Nine Months Ended						Nine Months Ended
	September 30, 2017						September 30, 2016						Change $
	Well		Processing				Well		Processing				Well		Processing
	Services		Solutions		Total		Services		Solutions		Total		Services		Solutions		Total
Net income (loss)	$	(22.3)	$	0.8	$	(21.5)	$	(1.3)	$	(0.6)	$	(1.9)	$	(21.0)	$	1.4	$	(19.6)
Interest expense, net		5.9		—		5.9		0.3		—		0.3		5.6		—		5.6
Tax expense		0.4		—		0.4		—		—		—		0.4		—		0.4
Depreciation and amortization		10.9		0.8		11.7		2.5		0.6		3.1		8.4		0.2		8.6
Equity based compensation		0.8		0.1		0.9		—		—		—		0.8		0.1		0.9
Acquisition related and severance costs		5.8		—		5.8		—		—		—		5.8		—		5.8
Costs incurred for offering related services		4.4		—		4.4		—		—		—		4.4		—		4.4
Adjusted EBITDA	$	5.9	$	1.7	$	7.6	$	1.5	$	—	$	1.5	$	4.4	$	1.7	$	6.1

Adjusted EBITDA for the nine months ended September 30, 2017 increased $6.1 million to $7.6 million from $1.5 million for the nine months ended September 30, 2016. The increase by segment was as follows:

Well Services. Well Services Adjusted EBITDA increased $4.4 million to $5.9 million from $1.5 million due mainly to significant increase in revenues of $75.9 million offset by a corresponding increase in cost of services of $64.0 million as well as an increase in general and administrative expenses of $18.4 million net of equity based compensation of $0.8 million, an increase in the tax provision of $0.4 million, acquisition related and severance costs of $5.8 million, and costs incurred for offering related services of $4.4 million.

Processing Solutions. Processing Solutions Adjusted EBITDA increased $1.7 million to $1.7 million from $0.0 million due primarily to an increase in net income (loss) of $1.4 million.

Liquidity and Capital Resources

Overview

We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions. Our primary sources of liquidity have been capital contributions from our owners and commercial borrowings and proceeds from the Offering. We expect our primary sources of liquidity will be cash generated from operations and borrowings under our Credit Facility. We strive to maintain financial flexibility and proactively monitor potential capital sources to meet our investment and target liquidity requirements and to permit us to manage the cyclicality associated with our business.

On August 16, 2017, we completed the Offering which resulted in net proceeds to Ranger of $80.8 million, after deducting $4.2 million of underwriting discounts and commissions. Ranger received net proceeds of approximately $20.7 million after we paid off the remainder of our long term debt of $10.4 million, funded $45.2 million for the cash portion of the ESCO Acquisition and paid $3.8 million in offering related costs and $0.7 million for cash bonuses to certain employees.

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As of September 30, 2017, we had cash on hand of approximately $20.7 million. Our cash on hand, expected cash flow from operations and availability under our Revolving Credit Facility (currently $20 million) are expected to be sufficient to meet the Company’s liquidity requirements for the next 12 months.

Cash Flows

The following table sets forth our cash flows for the periods indicated:


	Nine Months Ended
	September 30,				Change
	2017		2016		$		%
	(in millions)
Cash flows used in operating activities	$	(7.6)	$	(2.8)	$	4.8	(171)	%
Cash flows used in investing activities		(64.1)		(5.3)		58.8	(1,109)
Cash flows provided by financing activities		90.8		8.8		82.0	932
Net change in cash	$	19.1	$	0.7	$	18.4	2,629	%

Operating Activities

Net cash used in operating activities increased $4.8 million to $7.6 million for the nine months ended September 30, 2017 compared to $2.8 million for the nine months ended September 30, 2016. The change in cash flows used in operating activities is attributable to a higher net loss for the Company reduced by an increase in depreciation and amortization of $8.6 million and interest converted to equity of $5.2 million. The use of working capital cash for the nine months ended September 30, 2017 increased to $4.1 million as compared to the $4.0 million during the nine months ended September 30, 2016.

Investing Activities

Net cash used in investing activities increased $58.8 million to $64.1 million for the nine months ended September, 30, 2017 compared to $5.3 million for the nine months ended September 30, 2016. The change in cash flows used in investing activities is attributable to an increase in payments for purchases of property, plant and equipment of $11.1 million as well as $47.7 million used in the ESCO Acquisition.

Financing Activities

Net cash provided by financing activities increased $82.0 million to $90.8 million for the nine months ended September 30, 2017 compared to $8.8 million for the nine months ended September 30, 2016. The change in cash flows provided by financing activities is mostly attributable to the proceeds from the Offering of $80.8 million, net of underwriters’ expense of $4.2 million, as well as the proceeds from related party debt of $21.0 million. The proceeds were offset by a decrease in equity contributions of $7.6 million, an increase of $10.0 million in payments on third party debt, and payments of $3.8 million in costs from the Offering.

Supplemental Disclosures

We added assets worth $15.6 million that are non-cash additions in the current period. In addition we also purchased $7.6 million in assets via capital lease financing. The Company settled its related party debt of $21.0 million with the issuance of equity in conjunction with the Offering. In connection with the ESCO Acquisition the Company issued $5.0 million in Class A common stock as well as entered into two seller’s notes worth $7.0 million.

Working Capital

Our working capital, which we define as total current assets less total current liabilities, totaled $11.3 million and $10.4 million at and September 30, 2017 and December 31 2016, respectively.

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Our Debt Agreements

Ranger Services had a $5.0 million revolving line of credit with Iberia Bank expiring April 30, 2018 (the “Ranger Line of Credit”). As of December 31, 2016, there was $5.0 million borrowed against the Ranger Line of Credit. The Ranger Line of Credit was secured by substantially all of Ranger Services’ assets (approximately $107.9 million of the Predecessor’s total assets as of December 31, 2016). As of September 30, 2017, the Company paid the remaining balance and the Ranger Line of Credit has been closed. At December 31, 2016, the interest rate was 4.12%

In March 2015, Torrent Services, through certain members of its management team, secured a $0.6 million promissory note with Benchmark Bank, which was replaced in April 2016 with a $0.2 million promissory note with an interest rate of 4.5% and was secured by a $0.2 million certificate of deposit (the “Prior Torrent Note”). As of December 31, 2016 there was $0.2 million outstanding on the promissory note. The Prior Torrent Note was repaid in full on February 28, 2017.

In February 2015 (as amended in March 2016), Torrent Services secured a $2.0 million senior credit facility with Texas Capital Bank consisting of a $2.0 million advancing term loan. The note was secured by substantially all of Torrent Services’ assets (approximately $27.8 million of the Predecessor’s total assets as of December 31, 2016). Interest varied with the bank’s prime rate and the bank’s LIBOR and was payable quarterly through the maturity of the note. As of December 31, 2016, the interest rate was 5.75%. As of September 30, 2017, this note has been paid in full.

In April 2015, Ranger Services secured a $7.0 million loan from Iberia Bank, which is evidenced by a promissory note (the “Ranger Note”). Interest varies with the bank’s prime rate and the bank’s LIBOR and is payable in 60 equal monthly installments, which commenced on May 1, 2016. As of September 30, 2017 the Ranger Note has no outstanding balance and has been subsequently closed.

In February 2017, Ranger Services entered into loan agreements (collectively, the “Ranger Bridge Loan”) with each of CSL Opportunities II, CSL Holdings II and Bayou Well Holdings Company, LLC (“Bayou Holdings” and, together with CSL Opportunities II and CSL Holdings II, the “Bridge Loan Lenders”), each an indirect equity owner of Ranger Services, evidenced by promissory notes payable to each Bridge Loan Lender, in an aggregate principal amount of $11.1 million. Additional borrowings from CSL Opportunities II and CSL Holdings II increased the aggregate principal amount of the Ranger Bridge Loan to $12.1 million in April 2017, $14.6 million in May 2017 and $17.6 million in June 2017. In July 2017 borrowed an additional $3.4 million bringing the aggregate principal amount of the Bridge Loan to $21.0 million. The Ranger Bridge Loan was secured by substantially all of Ranger Services’ assets. Each note bore interest at a rate of 15% and matured upon the earlier of February 21, 2018 or ten days after the consummation of an initial public offering. The Ranger Bridge Loan includes a make‑whole provision pursuant to which Ranger Services will pay 125% of the total amount advanced to Ranger Services upon settlement. The Ranger Bridge Loan also requires Ranger Services to comply with certain non‑financial covenants. We repaid the Ranger Bridge Loan in connection the Offering by issuing 567,895 shares of our Class A Common Stock and 1,244,663 Ranger Units (and corresponding shares of our Class B common stock) to the Bridge Loan Lenders.

In connection with the Offering, we fully repaid and terminated the Ranger Line of Credit, the Ranger Note and the Ranger Bridge Loan and entered into a new credit agreement providing for a $50.0 million Credit Facility. The Credit Facility is subject to a borrowing base that is calculated by us based upon a percentage of the value of our eligible accounts receivable less certain reserves. The borrowing base is calculated on a monthly basis pursuant to a borrowing base certificate delivered by us to the administrative agent. The Credit Facility will be used for capital expenditures and permitted acquisitions, to provide for working capital requirements and for other general corporate purposes. The Credit Facility is secured by certain of our assets and contains various affirmative and negative covenants and restrictive provisions that limits our ability. The Company has approximately $20 million of borrowing capacity under the Credit Facility.

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Facility), less the amount, if any, of the Dilution Reserve (as defined in the Credit Facility), minus (ii) the aggregate amount of Reserves (as defined in the Credit Facility), if any, established by the Administrative Agent from time to time pursuant to the Credit Facility. The borrowing base is calculated on a monthly basis pursuant to a borrowing base certificate delivered by the Borrower to the Administrative Agent.

Borrowings under the Credit Facility bear interest, at our election, at either the (a) one-, two-, three- or six-month LIBOR or (b) the greatest of (i) the federal funds rate plus ½%, (ii) the one-month LIBOR plus 1% and (iii) the Administrative Agent’s prime rate (the “Base Rate”), in each case plus an applicable margin, and interest shall be payable monthly in arrears. The applicable margin for LIBOR loans ranges from 1.50% to 2.00% and the applicable margin for Base Rate loans ranges from 0.50% to 1.00%, in each case, depending on our average excess availability under the Credit Facility. The applicable margin for LIBOR loans is 1.50% and the applicable margin for Base Rate loans is 0.50% until August 31, 2018. During the continuance of a bankruptcy event of default, automatically and during the continuance of any other default, upon the Administrative Agent’s or the required lenders’ election, all outstanding amounts under the Credit Facility bears interest at 2.00% plus the otherwise applicable interest rate. The Credit Facility is scheduled to mature on the fifth anniversary of the consummation of the Offering (August 16, 2022).

In addition, the Credit Facility restricts our ability to make distributions on, or redeem or repurchase, our equity interests, except for certain distributions, including distributions of cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Facility and either (a) excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 22.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $10.0 million or (b) if our fixed charge coverage ratio is at least 1.0x on a pro forma basis, excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 17.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $7.0 million. If the foregoing threshold under clause (b) is met, we may not make such distributions (but may make certain other distributions, including under clause (a) above) prior to the earlier of the date that is (a) 12 months from closing or (b) the date that our fixed charge coverage ratio is at least 1.0x for two consecutive quarters. Our Credit Facility generally permits us to make distributions required under the Tax Receivable Agreement, but a ‘‘Change of Control’’ under the Tax Receivable Agreement constitutes an event of default under our Credit Facility, and our Credit Facility does not permit us to make payments under the Tax Receivable Agreement upon acceleration of our obligations thereunder unless no event of default exists or would result therefrom and we have been in compliance with the fixed charge coverage ratio for the most recent 12-month period on a pro forma basis. Our Credit Facility also requires us to maintain a fixed charge coverage ratio of at least 1.0x if our liquidity is less than $10.0 million until our liquidity is at least $10.0 million for thirty consecutive days. We are not be subject to a fixed charge coverage ratio if we have no drawings under the Credit Facility and have at least $20.0 million of qualified cash.

The Credit Facility contains events of default customary for facilities of this nature, including, but not limited, to:

• events of default resulting from our failure or the failure of any guarantors to comply with covenants and financial ratios;

• the occurrence of a change of control;

• the institution of insolvency or similar proceedings against us or any guarantor; and

• the occurrence of a default under any other material indebtedness we or any guarantor may have.

Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Facility, the lenders are able to declare any outstanding principal of our Credit Facility debt, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies.

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Contractual and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments as of September 30, 2017:


			Less than						More than
	Total		1 year		1 - 3 years		3 - 5 years		5 years
	(in millions)
Long-term debt obligations	$	7.0	$	1.2	$	5.8	$	—	$	—
Capital lease obligations		9.0		7.6		1.4		—		—
Operating lease obligations		5.9		0.5		5.0		0.4		—
Total	$	21.9	$	9.3	$	12.2	$	0.4	$	—

In addition to the contractual obligations and commercial commitments as of September 30, 2017 listed in the table above, we have entered into agreements during 2017, including the purchase agreement with National Oilwell Varco, L.P., pursuant to which we have acquired 22 high spec well service rigs as of September 30, 2017 and expect to acquire an additional 15 high spec well service rigs during the remainder of 2017 for an aggregate purchase price under such agreements, including change orders, of approximately $43.5 million for which $3.5 million of payments have been made as of September 30, 2017, and the remaining $40.0 million of which will be due during the remainder of 2017 and 2018.

Tax Receivable Agreement

With respect to obligations we expect to incur under our Tax Receivable Agreement (except in cases where we elect to terminate the Tax Receivable Agreement early, the Tax Receivable Agreement is terminated early due to certain mergers, asset sales, other forms of business combination or other changes of control or we have available cash but fail to make payments when due), generally we may elect to defer payments due under the Tax Receivable Agreement if we do not have available cash to satisfy our payment obligations under the Tax Receivable Agreement or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the Tax Receivable Agreement generally will accrue interest. In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement. We intend to account for any amounts payable under the Tax Receivable Agreement in accordance with ASC 450, Contingencies. Further, we intend to account for the effect of increases in tax basis and payments for such increases under the Tax Receivable Agreement arising from future redemptions as follows:

when future sales or redemptions occur, we will record a deferred tax liability for the gross amount of the income tax effect along with an offset of 85% of this liability as payable under the Tax Receivable Agreement; the remaining difference between the deferred tax liability and tax receivable agreement liability will be recorded as additional paid‑in capital; and

to the extent we have recorded a deferred tax asset for an increase in tax basis to which a benefit is no longer expected to be realized due to lower future taxable income, we will reduce the deferred tax asset with a valuation allowance.

Critical Accounting Policies and Estimates

There were no changes to our critical accounting policies from those disclosed in our Final Prospectus filed on August 14, 2017.

Recent Accounting Pronouncements

For information regarding new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, please refer to Note 2- Summary of Significant Accounting Policies in Part I, Item 1 of this Quarterly Report, which is incorporated herein by reference.

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Off‑Balance Sheet Arrangements

We currently have no material off‑balance sheet arrangements.

Jumpstart Our Business Act of 2012

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). We will remain an emerging growth company until the earlier of (1) the last day of our fiscal year (a) following the fifth anniversary of the completion of the Offering, (b) in which we have total annual gross revenue of at least $1.07 billion, or (c) in which we are deemed to be a large accelerated filer, which means the market value of our common stock that is held by non-affiliates exceeds $700.0 million as of the last business day of our most recently completed second fiscal quarter, and (2) the date on which we have issued more than $1.0 billion in non-convertible debt securities during the prior three-year period. An emerging growth company may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies. We have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Form 10‑Q includes “forward‑looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward‑looking statements. When used in this Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward‑looking statements, although not all forward‑looking statements contain such identifying words. These forward‑looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward‑looking statements, you should keep in mind the risk factors and other cautionary statements included in the Final Prospectus. These forward‑looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward‑looking statements may include statements about:

our business strategy;

our operating cash flows, the availability of capital and our liquidity;

our future revenue, income and operating performance;

our ability to sustain and improve our utilization, revenues and margins;

our ability to maintain acceptable pricing for our services;

our future capital expenditures;

our ability to finance equipment, working capital and capital expenditures;

competition and government regulations;

our ability to obtain permits and governmental approvals;

pending legal or environmental matters;

marketing of oil and natural gas;

business or asset acquisitions, including the ESCO Acquisition;

general economic conditions;

credit markets;

our ability to successfully develop our research and technology capabilities and implement technological developments and enhancements;

uncertainty regarding our future operating results; and

plans, objectives, expectations and intentions contained in this report that are not historical.

We caution you that these forward‑looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, the risks described under “Risk Factors” in the Final Prospectus previously filed. Should one or more of the risks or uncertainties described occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward‑looking statements.

All forward‑looking statements, expressed or implied, included in this Form 10‑Q are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward‑looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward‑looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Form 10‑Q.

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Item 3. Quantitative and Qualitative Disclosure about Market Risks

The demand, pricing and terms for oil and natural gas services provided by us are largely dependent upon the level of activity for the U.S. oil and natural gas industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; available pipeline and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil‑producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers to raise equity capital and debt financing; and merger and divestiture activity among oil and natural gas producers.

Interest Rate Risk

We had an aggregate of $7.0 million outstanding under notes payable from the ESCO Acquisition at September 30, 2017, with a weighted average interest rate of 5.0%. A 1.0% increase or decrease in the weighted average interest rate would increase or decrease interest expense by approximately $0.1 million per year. We do not currently hedge our interest rate exposure.

Credit Risk

The majority of our trade receivables have payment terms of 30 days or less. As of September 30, 2017, the top three trade receivable balances represented 13%, 9% and 8%, respectively, of total accounts receivable. Within our Well Services segment, the top three trade receivable balances represented 13%, 9% and 8%, respectively, of total Well Services accounts receivable. Within our Processing Solutions segment, the top three trade receivable balances represented 57%, 16% and 15%, respectively, of total Processing Solutions accounts receivable. We mitigate the associated credit risk by performing credit evaluations and monitoring the payment patterns of our customers.

Commodity Price Risk

The market for our services is indirectly exposed to fluctuations in the prices of oil and natural gas to the extent such fluctuations impact the activity levels of our E&P customers. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. We do not currently intend to hedge our indirect exposure to commodity price risk.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As required by Rule 13a‑15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d‑15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10‑Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. As of September 30, 2017 disclosure controls and procedures were not effective as a result of the material weakness identified during the year ended December 31, 2016. The material weakness related to the lack of sufficient qualified accounting personnel, which led to the incorrect application of generally accepted accounting principles, ineffective controls over accounting for non-routine and/or complex transactions, and ineffective controls over the financial statement close and reporting processes.

We have recruited additional finance and accounting personnel and we continue to evaluate our personnel in all key finance and accounting positions to see if additional finance and accounting personnel are required.

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Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION

ITEM 1. Legal Proceedings

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently subject to any material litigation and in the opinion of management, the outcome of any existing matters will not have a material adverse effect on the Company’s consolidated financial position or consolidated results of operations. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisers and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available in the future at economical prices.

Item 1A. Risk Factors.

Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our Class A Common Stock are described under “Risk Factors”, included in our Final Prospectus. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

Item 6. Exhibits

The exhibits listed on the accompanying Exhibit Index are filed, furnished or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

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INDEX TO EXHIBITS


Exhibit Number		Description
3.1		Amended and Restated Certificate of Incorporation of Ranger Energy Services, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
3.2		Amended and Restated Bylaws of Ranger Energy Services, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
4.1		Registration Rights Agreement (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
4.2		Stockholders’ Agreement (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.1		Amended and Restated Limited Liability Company Agreement of RNGR Energy Services, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K (File No. 001-38183) filed with the Commission on August 22, 2017)
10.2†		Ranger Energy Services, Inc. Long Term Incentive Plan (incorporated by reference to Exhibit 4.7 to the Registrant’s Form S‑8 Registration Statement (File No. 333‑220018) filed with the Commission on August 17, 2017)
10.3†		Form of Restricted Stock Agreement (Employees) under the Ranger Energy Services, Inc. 2017 Long Term Incentive Plan. (incorporated by reference to Exhibit 4.8 to the Registrant’s Form S‑8 Registration Statement (File No. 333‑220018) filed with the Commission on August 17, 2017)
10.4†		Form of Restricted Stock Agreement (Directors) under the Ranger Energy Services, Inc. 2017 Long Term Incentive Plan. (incorporated by reference to Exhibit 4.9 to the Registrant’s Form S‑8 Registration Statement (File No. 333‑220018) filed with the Commission on August 17, 2017)
10.5		Tax Receivable Agreement (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.6		Credit Agreement (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.7‡		Second Amended and Restated Purchase Agreement, dated as of July 3, 2017, by and among Ranger Energy Services, LLC, Ranger Energy Leasing, LLC, Ranger Energy Services, Inc. and National Oilwell Varco, L.P. (incorporated by reference to Exhibit 10.7 to the Registrant’s Form S‑1/A Registration Statement (File No. 333‑218139) filed with the Commission on August 7, 2017)
10.8†		Indemnification Agreement (Darron M. Anderson) incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K (File No. 001-38183) filed with the Commission on August 22, 2017)
10.9†		Indemnification Agreement (William M. Austin) (incorporated by reference to Exhibit 10.5 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.10†		Indemnification Agreement (Brett T. Agee) (incorporated by reference to Exhibit 10.6 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.11†		Indemnification Agreement (Richard E. Agee) (incorporated by reference to Exhibit 10.7 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.12†		Indemnification Agreement (John Matthew Hooker) (incorporated by reference to Exhibit 10.8 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.13†		Indemnification Agreement (Charles S. Leykum) (incorporated by reference to Exhibit 10.9 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.14†		Indemnification Agreement (Merrill A. Miller Jr.) (incorporated by reference to Exhibit 10.10 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.15†		Indemnification Agreement (Lance A. Perryman) (incorporated by reference to Exhibit 10.11 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.16†		Indemnification Agreement (Vivek Raj) (incorporated by reference to Exhibit 10.12 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)

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10.17†		Indemnification Agreement (Robert S. Shaw Jr.) (incorporated by reference to Exhibit 10.13 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
10.18†		Indemnification Agreement (Krishna Shivram) (incorporated by reference to Exhibit 10.14 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
*31.1		Certification of Chief Executive Officer Pursuant to Rule 13a‑14(a)/15d‑14(a) of the Securities Exchange Act of 1934
*31.2		Certification of Chief Financial Officer Pursuant to Rule 13a‑14(a)/15d‑14(a) of the Securities Exchange Act of 1934
**32.1		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.CAL		XBRL Calculation Linkbase Document
*101.DEF		XBRL Definition Linkbase Document
*101.INS		XBRL Instance Document
*101.LAB		XBRL Labels Linkbase Document
*101.PRE		XBRL Presentation Linkbase Document
*101.SCH		XBRL Schema Document

* Filed as an exhibit to this Quarterly Report on Form 10-Q

** Furnished as an exhibit to this Quarterly Report on Form 10-Q

† Compensatory plan or arrangement

†† Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant will furnish a supplemental copy of any omitted schedule or similar attachment to the SEC upon request.

‡Confidential treatment was granted with respect to certain portions of this exhibit. Omitted portions filed separately with the SEC.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	Ranger Energy Services, Inc.


November 9, 2017	By:	/s/ Darron M. Anderson
	NAME:	Darron M. Anderson
	Title:	President, Chief Executive Officer and Director
		(Principal Executive Officer)


November 9, 2017	By:	/s/ Robert S. Shaw Jr.
	NAME:	Robert S. Shaw Jr.
	Title:	Chief Financial Officer
		(Principal Financial Officer and Principal Accounting Officer)

Ranger Energy Services, Inc. - FORM 10-Q - November 9, 2017

Attached files

Ranger Energy Services, Inc. Reports