Item 1.
|
Financial Statements
|
Quintana Energy Services Inc.
Condensed Consolidated Balance Sheets
(
in thousands of dollars and shares, except per share data
)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
|
December 31, 2017
|
|
Assets
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
16,646
|
|
|
$
|
8,751
|
|
Accounts receivable, net of allowance of $897 and $776
|
|
|
84,577
|
|
|
|
83,325
|
|
Unbilled receivables
|
|
|
8,223
|
|
|
|
9,645
|
|
Inventories
|
|
|
26,482
|
|
|
|
22,693
|
|
Prepaid expenses and other current assets
|
|
|
9,775
|
|
|
|
9,520
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
145,703
|
|
|
|
133,934
|
|
Property, plant and equipment, net
|
|
|
129,573
|
|
|
|
128,518
|
|
Intangible assets, net
|
|
|
10,379
|
|
|
|
10,832
|
|
Other assets
|
|
|
1,635
|
|
|
|
2,375
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
287,290
|
|
|
$
|
275,659
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders Equity
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Current portion of debt and capital lease obligations
|
|
$
|
380
|
|
|
$
|
79,443
|
|
Accounts payable
|
|
|
40,347
|
|
|
|
36,027
|
|
Accrued liabilities
|
|
|
32,382
|
|
|
|
33,825
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
73,109
|
|
|
|
149,295
|
|
Deferred tax liability
|
|
|
|
|
|
|
185
|
|
Long-term debt, net of deferred financing costs of $0 and $1,709
|
|
|
13,000
|
|
|
|
37,199
|
|
Long-term capital lease obligations
|
|
|
3,731
|
|
|
|
3,829
|
|
Other long-term liabilities
|
|
|
171
|
|
|
|
183
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
90,011
|
|
|
|
190,691
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Shareholders and members equity
|
|
|
|
|
|
|
|
|
Members equity
|
|
|
|
|
|
|
212,630
|
|
Preferred shares, $0.01 par value, 10,000 authorized; 0 issued and outstanding
|
|
|
|
|
|
|
|
|
Common shares, $0.01 par value, 150,000 authorized; 33,765 issued; 33,631 outstanding
|
|
|
336
|
|
|
|
|
|
Additional paid in capital
|
|
|
342,047
|
|
|
|
|
|
Treasury stock, at cost, 135 common shares
|
|
|
(1,271
|
)
|
|
|
|
|
Retained deficit
|
|
|
(143,833
|
)
|
|
|
(127,662
|
)
|
|
|
|
|
|
|
|
|
|
Total shareholders and members equity
|
|
|
197,279
|
|
|
|
84,968
|
|
|
|
|
|
|
|
|
|
|
Total liabilities, shareholders and members equity
|
|
$
|
287,290
|
|
|
$
|
275,659
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
1
Quintana Energy Services Inc.
Condensed Consolidated Statements of Operations
(
in thousands of dollars and units, except per share data
)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31, 2018
|
|
|
March 31, 2017
|
|
Revenues:
|
|
$
|
141,268
|
|
|
$
|
85,439
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
106,492
|
|
|
|
66,836
|
|
General and administrative expenses
|
|
|
29,917
|
|
|
|
17,744
|
|
Depreciation and amortization
|
|
|
11,078
|
|
|
|
11,594
|
|
Gain on disposition of assets
|
|
|
(106
|
)
|
|
|
(1,657
|
)
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(6,113
|
)
|
|
|
(9,078
|
)
|
Interest expense
|
|
|
(10,192
|
)
|
|
|
(2,601
|
)
|
|
|
|
|
|
|
|
|
|
Loss before tax
|
|
|
(16,305
|
)
|
|
|
(11,679
|
)
|
Income tax (expense) benefit
|
|
|
(51
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
Net Loss
|
|
|
(16,356
|
)
|
|
|
(11,673
|
)
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Predecessor
|
|
|
(1,546
|
)
|
|
|
(11,673
|
)
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Quintana Energy Services Inc.
|
|
$
|
(14,810
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.44
|
)
|
|
$
|
|
|
Diluted
|
|
$
|
(0.44
|
)
|
|
$
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
33,318
|
|
|
|
|
|
Diluted
|
|
|
33,318
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
Quintana Energy Services Inc.
Condensed Consolidated Statement of Shareholders Equity
(
in thousands of dollars, units and shares
)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Unitholders
Number of
Units
|
|
|
Members
Equity
|
|
|
Common
Shareholders
Number of
Shares
Outstanding
|
|
|
Common
Stock
|
|
|
Additional
Paid in
Capital
|
|
|
Treasury
Stock
|
|
|
Retained
Deficit
|
|
|
Total
Shareholders
Equity
|
|
Balance at December 31, 2017
|
|
|
417,441
|
|
|
$
|
212,630
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(127,662
|
)
|
|
$
|
84,968
|
|
Effect of Reorganization Transactions
|
|
|
(417,441
|
)
|
|
|
(212,630
|
)
|
|
|
23,598
|
|
|
|
236
|
|
|
|
246,027
|
|
|
|
|
|
|
|
|
|
|
|
33,633
|
|
Issuance of common stock sold in initial public offering, net of offering costs
|
|
|
|
|
|
|
|
|
|
|
9,632
|
|
|
|
96
|
|
|
|
90,445
|
|
|
|
|
|
|
|
|
|
|
|
90,541
|
|
Net loss prior to Reorganization Transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,546
|
)
|
|
|
(1,546
|
)
|
Cost incurred for stock issuance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,307
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,307
|
)
|
Equity-based compensation
|
|
|
|
|
|
|
|
|
|
|
401
|
|
|
|
4
|
|
|
|
9,882
|
|
|
|
|
|
|
|
|
|
|
|
9,886
|
|
Activity related to stock plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,271
|
)
|
|
|
|
|
|
|
(1,271
|
)
|
Opening deferred tax adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
185
|
|
|
|
185
|
|
Net loss subsequent to Reorganization Transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,810
|
)
|
|
|
(14,810
|
)
|
Balance at March 31, 2018
|
|
|
|
|
|
$
|
|
|
|
|
33,631
|
|
|
$
|
336
|
|
|
$
|
342,047
|
|
|
$
|
(1,271
|
)
|
|
$
|
(143,833
|
)
|
|
$
|
197,279
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
Quintana Energy Services Inc.
Condensed Consolidated Statements of Cash Flows
(
in thousands of dollars
)
(
Unaudited
)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31, 2018
|
|
|
March 31, 2017
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(16,356
|
)
|
|
$
|
(11,673
|
)
|
Adjustments to reconcile net loss to net cash used in operating activities
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
11,078
|
|
|
|
11,594
|
|
Gain on disposition of assets
|
|
|
(458
|
)
|
|
|
(4,623
|
)
|
Non cash interest expense
|
|
|
764
|
|
|
|
264
|
|
Loss on debt extinguishment
|
|
|
8,594
|
|
|
|
|
|
Provision for doubtful accounts
|
|
|
159
|
|
|
|
57
|
|
Deferred income tax benefit
|
|
|
|
|
|
|
(18
|
)
|
Stock-based compensation
|
|
|
9,886
|
|
|
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(1,411
|
)
|
|
|
(14,180
|
)
|
Unbilled receivables
|
|
|
1,422
|
|
|
|
(2,070
|
)
|
Inventories
|
|
|
(3,789
|
)
|
|
|
(430
|
)
|
Prepaid expenses and other current assets
|
|
|
459
|
|
|
|
(749
|
)
|
Other noncurrent assets
|
|
|
|
|
|
|
(213
|
)
|
Accounts payable
|
|
|
1,508
|
|
|
|
(2,592
|
)
|
Accrued liabilities
|
|
|
(1,448
|
)
|
|
|
5,158
|
|
Other long-term liabilities
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
10,401
|
|
|
|
(19,475
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
Purchases of property, plant and equipment
|
|
|
(10,705
|
)
|
|
|
(4,212
|
)
|
Advances of deposit on equipment
|
|
|
(1,709
|
)
|
|
|
|
|
Proceeds from sale of property, plant and equipment
|
|
|
998
|
|
|
|
28,428
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by investing activities
|
|
|
(11,416
|
)
|
|
|
24,216
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
Proceeds from revolving debt
|
|
|
15,000
|
|
|
|
|
|
Payments on revolving debt
|
|
|
(81,071
|
)
|
|
|
(10,929
|
)
|
Proceeds from term loans
|
|
|
|
|
|
|
5,000
|
|
Payments on term loans
|
|
|
(11,225
|
)
|
|
|
|
|
Payments on capital lease obligations
|
|
|
(90
|
)
|
|
|
(75
|
)
|
Payment of deferred financing costs
|
|
|
(1,416
|
)
|
|
|
|
|
Prepayment premiums on early debt extinguishment
|
|
|
(1,346
|
)
|
|
|
|
|
Payments for treasury shares
|
|
|
(1,271
|
)
|
|
|
|
|
Proceeds from new shares issuance, net of underwriting commission costs
|
|
|
90,541
|
|
|
|
|
|
Costs incurred for stock issuance
|
|
|
(212
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
8,910
|
|
|
|
(6,004
|
)
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
7,895
|
|
|
|
(1,263
|
)
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
8,751
|
|
|
|
12,219
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
16,646
|
|
|
$
|
10,956
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
|
792
|
|
|
|
1,100
|
|
Income taxes paid
|
|
|
|
|
|
|
166
|
|
Supplemental noncash investing and financing activities
|
|
|
|
|
|
|
|
|
Noncash proceeds from sale of assets held for sale
|
|
|
|
|
|
|
3,990
|
|
Fixed asset purchases in accounts payable and accrued liabilities
|
|
|
832
|
|
|
|
|
|
Non cash payment for property, plant and equipment
|
|
|
682
|
|
|
|
|
|
Debt conversion of term loan to equity
|
|
|
33,632
|
|
|
|
|
|
Issuance of common shares for members equity
|
|
|
212,630
|
|
|
|
|
|
Stock issuance cost included in accounts payable
|
|
|
1,967
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
4
NOTE 1 ORGANIZATION AND NATURE OF OPERATIONS
Quintana Energy Services Inc. (either individually or together with its subsidiaries, as the context requires, the Company,
QES, we, us, and our) is a Delaware corporation that was incorporated on April 13, 2017. Our accounting predecessor, Quintana Energy Services LP (QES LP and Predecessor),
was formed as a Delaware partnership on November 3, 2014. In connection with our initial public offering (the IPO) which closed on February 13, 2018, the existing investors in QES LP and QES Holdco LLC contributed all of their
direct and indirect equity interests to QES in exchange for shares of common stock in QES, and we became the holding company for the reorganized QES LP and its subsidiaries.
We are a growth-oriented provider of diversified oilfield services to leading onshore oil and natural gas exploration and production
(E&P) companies operating in both conventional and unconventional plays in all of the active major basins throughout the United States. The Company operates through four reporting segments, which are Directional Drilling, Pressure
Pumping, Pressure Control and Wireline.
Initial Public Offering
As of December 31, 2017, our Predecessor had 417,441,074 common units outstanding and 227,885,579 warrants to purchase common units
outstanding. Immediately prior to the IPO on February 13, 2018, the warrants were net settled for 223,394,762 common units, and immediately thereafter our Predecessor and affiliated entities were reorganized through mergers and related
transactions and 20,235,193 shares of our common stock were issued to the holders of equity in our Predecessor at a ratio of 1 share of our common stock for 31.669363 common units of our Predecessor (with elimination of fractional shares) (the
Merger Transactions). On February 13, 2018, immediately after the Merger Transactions, but prior to our IPO, our Predecessors Former Term Loan (as defined below) was extinguished and in partial consideration therefor 3,363,208
shares were issued to our Predecessors Former Term Loan lenders based on the price to the public of our IPO (representing 1 share of common stock for each $10.00 in Former Term Loan obligations converted) (together with the Merger
Transactions, the Reorganization Transactions).
The gross proceeds of the IPO to the Company, at the public offering
price of $10.00 per share, was $92.6 million, which resulted in net proceeds to the Company of approximately $87.0 million, after deducting $5.6 million of underwriting discounts and commissions associated with the shares sold by the
Company, excluding approximately $4.2 million in offering expenses payable by the Company. Taking together the Reorganization Transactions and the issuance of 9,259,259 shares of our common stock to the public in our IPO, as of
February 13, 2018, we had 32,857,660 shares outstanding immediately following our IPO. Subsequent to our IPO, we issued 139,921 shares in connection with the vesting of awards under our Predecessors 2015 LTIP Plan on February 22,
2018, and 260,529 shares of our common stock were issued on March 8, 2018 in consideration of vesting of awards under our Predecessors 2017 LTIP which we assumed. In connection with both awards, certain shares were withheld to satisfy tax
obligations of the holder of the award, which shares are currently treasury shares totaling 134,552 shares of common stock. Also in connection with the consummation of the IPO, on March 9, 2018, the underwriters exercised their overallotment
option to purchase an additional 372,824 shares of common stock of QES, which resulted in additional net proceeds of approximately $3.5 million (the Option Exercise), net of underwriters discounts and commission of
$0.1 million. Upon the completion of the Reorganizational Transactions, the IPO and the Option Exercise, QES had 33,630,934 shares of common stock outstanding.
The net proceeds received from the IPO and a $13.0 million drawdown on the New ABL Facility (described below) were used to fully repay
the Companys revolving credit facility balance of $81.1 million and repay $12.6 million of the Companys $40.0 million, 10% term loan due 2020 (the Former Term Loan), as described in Note
5-Long-Term
Debt and Capital Lease Obligations. The remaining proceeds from the IPO will be used for general corporate purposes.
NOTE 2 BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
The accompanying interim condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted
in the United States of America (U.S. GAAP). These interim condensed consolidated financial accounts include all QES accounts and all of our subsidiaries where we exercise control. All inter-company transactions and account balances have
been eliminated upon consolidation.
5
The accompanying interim condensed consolidated financial statements have not been audited by the
Companys independent registered public accounting firm, except that the Consolidated Balance Sheet at December 31, 2017, is derived from previously audited consolidated financial statements. In the opinion of management, all material
adjustments, consisting of normal recurring adjustments, necessary for fair statement have been included.
These interim condensed
consolidated financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (SEC) for interim financial information. Accordingly, they do not include all of the information
and notes required by U.S. GAAP for complete financial statements. Therefore, these interim condensed consolidated financial statements should be read in conjunction with the Companys audited consolidated financial statements and notes
included in the Companys Annual Report on Form
10-K
for the year ended December 31, 2017 (2017 Annual Report) filed with the SEC on March 30, 2018. The operating results for interim
periods are not necessarily indicative of results that may be expected for any other interim period or for the full year.
There have been
no material changes to the Companys critical accounting policies or estimates from those disclosed in the 2017 Annual Report. The Company adopted certain accounting policies including the adoption of the Financial Accounting Standards Board
(FASB) Accounting Standards Update (ASU)
No. 2014-09,
Revenue from Contracts with Customers (the new revenue standard or Accounting Standards Codification 606,
(ASC 606)) on January 1, 2018. These revenue recognition policy updates are applied prospectively in our financial statements from January 1, 2018 forward. Reported financial information for the historical comparable period was
not revised and continues to be reported under the accounting standards in effect during the historical periods as there is not a material impact related to adoption. For additional discussion of this adoption, see Note 11, Revenues for
Contracts with Customers.
Recent Accounting Pronouncements
Adopted in 2018
In May 2014, the
FASB issued ASU
No. 2014-09,
Revenue from Contracts with Customers (Topic 606)
, a comprehensive new revenue recognition standard that supersedes most existing industry-specific guidance. ASC 606
creates a framework by which an entity allocates the transaction price to separate performance obligations and recognizes revenue when each performance obligation is satisfied. Under the new standard, entities are required to use judgment and make
estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation and determining
when an entity satisfies its performance obligations. The standard allows for either full retrospective adoption, meaning that the standard is applied to all of the periods presented with a cumulative
catch-up
as of the earliest period presented, or modified retrospective adoption, meaning the standard is applied only to the most current period presented in the financial statements with a
cumulative
catch-up
in the current period. In July and December 2016, the FASB issued various additional authoritative guidance for the new revenue recognition standard. The accounting standard is effective
for reporting periods beginning after December 15, 2017 and did not have a material impact on the Companys 2018 first quarter interim condensed consolidated financial position, results of operations and cash flows. The Company adopted ASC
606, effective January 1, 2018, utilizing the modified retrospective method of adoption. See Note 11, Revenue from Contracts with Customers, for more details on the adoption and impacts of implementing ASC 606.
In January 2017, FASB issued ASU
No. 2017-01,
Business Combinations (Topic 805):
Clarifying
the Definition of a Business
. The amendments provide a more robust framework to use in determining when a set of assets and activities constitutes a business. The new standard was effective for the Company beginning on January 1, 2018. The
standard did not have a material impact on the Companys interim condensed consolidated financial position, results of operations and cash flows as it did not have any business combinations transactions.
In May 2017, the FASB issued ASU
2017-09,
Compensation (Topic 718): Scope of Modification
Accounting
, which clarifies what constitutes a modification of a share-based payment award. The new standard was effective for the Company beginning on January 1, 2018. The standard did not have a material impact on the Companys
interim condensed consolidated financial position, results of operations and cash flows because there has been no modification to our equity-based payment awards.
6
In August 2016, the FASB issued ASU
2016-15,
Classification of Certain Cash Receipts and Cash Payments
providing new guidance on the classification of certain cash receipts and payments including debt extinguishment costs, debt prepayment costs, settlement of
zero-coupon
debt instruments, contingent consideration payments, proceeds from the settlement of insurance claims and life insurance policies and distributions received from equity method investees in the statement
of cash flows. This update is required to be applied using the retrospective transition method to each period presented unless it is impracticable to be applied retrospectively. In such situation, this guidance is to be applied prospectively. The
new standard was effective for the Company beginning on January 1, 2018, which did not impact 2017 results, but resulted in a $1.3 million prepayment premium cost being reported under financing activities relating to the debt
extinguishment of the Companys $40.0 million term loan at the closing of the IPO.
Accounting Standards not yet adopted
In February 2016, the FASB issued ASU
No. 2016-02,
Leases.
The new standard requires
lessees to recognize a right of use asset and a lease liability for virtually all leases. The guidance is effective for the Company for the fiscal year beginning January 1, 2019. While the exact impact of this standard is not known, the
guidance is expected to have a material impact on the Companys consolidated financial statements, due to the leased assets and corresponding lease liability that will be recognized, as the Company has operating and real property lease
arrangements for which it is the lessee.
NOTE 3 Inventories
Inventories consisted of the following (
in thousands of dollars
):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
Consumables and materials
|
|
$
|
8,658
|
|
|
$
|
7,085
|
|
Spare parts
|
|
|
17,824
|
|
|
|
15,608
|
|
|
|
|
|
|
|
|
|
|
Inventories
|
|
$
|
26,482
|
|
|
$
|
22,693
|
|
|
|
|
|
|
|
|
|
|
NOTE 4 Accrued Liabilities
Accrued liabilities consist of the following (
in thousands of dollars
):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
Current accrued liabilities
|
|
|
|
|
|
|
|
|
Accrued payables
|
|
$
|
15,416
|
|
|
$
|
11,905
|
|
Payroll and payroll taxes
|
|
|
3,537
|
|
|
|
6,089
|
|
Bonus
|
|
|
3,308
|
|
|
|
6,019
|
|
Workers compensation insurance premiums
|
|
|
1,802
|
|
|
|
1,760
|
|
Sales tax
|
|
|
2,395
|
|
|
|
2,923
|
|
Ad valorem tax
|
|
|
683
|
|
|
|
728
|
|
Health insurance claims
|
|
|
1,181
|
|
|
|
913
|
|
Other accrued liabilities
|
|
|
4,060
|
|
|
|
3,488
|
|
|
|
|
|
|
|
|
|
|
Total accrued liabilities
|
|
$
|
32,382
|
|
|
$
|
33,825
|
|
|
|
|
|
|
|
|
|
|
7
NOTE 5 Long-Term Debt and Capital Lease Obligations
Long-term debt consisted of the following (
in thousands of dollars
):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
New ABL revolving credit facility due February 2023
|
|
$
|
13,000
|
|
|
$
|
|
|
Revolving credit facility
|
|
|
|
|
|
|
79,071
|
|
2017 term loan facility
|
|
|
|
|
|
|
44,328
|
|
Less: deferred financing costs
|
|
|
|
|
|
|
(1,709
|
)
|
Less: discount on term loan
|
|
|
|
|
|
|
(5,420
|
)
|
|
|
|
|
|
|
|
|
|
Total debt obligations, net of discounts and deferred financing
|
|
|
13,000
|
|
|
|
116,270
|
|
Capital leases
|
|
|
4,111
|
|
|
|
4,200
|
|
Less: current portion of debt and capital lease obligation
|
|
|
(380
|
)
|
|
|
(79,442
|
)
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations
|
|
$
|
16,731
|
|
|
$
|
41,028
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
Former
Revolving Credit Facility
The Company had a revolving credit facility (the Former Revolving Credit Facility), which had a
maximum borrowing facility of $110.0 million that was scheduled to mature on September 19, 2018. All obligations under the credit agreement for the Former Revolving Credit Facility were collateralized by substantially all of the assets of
the Company. The Revolving Credit Facilitys credit agreement contained customary restrictive covenants that required the Company not to exceed or fall below two key ratios, a maximum loan to value ratio of 70% and a minimum liquidity of
$7.5 million. In connection with the closing of the IPO on February 13, 2018, we fully repaid and terminated the Former Revolving Credit Facility. No early termination fees were incurred by the Company in connection with the termination of
the Former Revolving Credit Facility. A loss on extinguishment of $0.3 million relating to unamortized deferred costs was recognized in interest expense.
Former Term Loan
The Company also had a
four-year, $40.0 million term loan agreement with a lending group, which included Archer Well Company Inc. (Archer) and an affiliate of Quintana Capital Group, L.P. (Quintana) that was scheduled to mature on
December 19, 2020. The Former Term Loan agreement contained customary restrictive covenants that required the Company not to exceed or fall below two key ratios, a maximum loan to value ratio of 77% and a minimum liquidity of
$6.75 million. The interest rate on the unpaid principal was 10.0% interest per annum and accrued on a daily basis. At the end of each quarter all accrued and unpaid interest was paid in kind by capitalizing and adding to the outstanding
principal balance. In connection with the closing of the IPO on February 13, 2018, the Former Term Loan was settled in full by cash and common shares in the company. In connection with the settlement of the Former Term Loan, a prepayment fee of
3%, or approximately $1.3 million was paid. The prepayment fee is recorded as a loss on extinguishment and included within interest expense. The Company also recognized $5.4 million of unamortized discount expense and $1.7 million of
unamortized deferred financing cost.
New ABL Facility
In connection with the closing of the IPO on February 13, 2018, we entered into a new semi-secured asset-based revolving credit agreement
(the New ABL Facility) with each lender party thereto and Bank of America, N.A. as administrative agent and collateral agent. The New ABL Facility replaced the Former Revolving Credit Facility, which was terminated in conjunction with
the effectiveness of the New ABL Facility. The New ABL Facility provides for a $100.0 million revolving credit facility subject to a borrowing base. Upon closing of the New ABL the borrowing capacity was $77.6 million and
$13.0 million was immediately drawn. The loan interest rate on the borrowings outstanding at March 31, 2018, was 4.63%. As of March 31, 2018, $13.0 million was outstanding under the New ABL Facility.
8
The New ABL Facility contains various affirmative and negative covenants, including financial
reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions) and transactions with affiliates.
Certain affirmative covenants, including certain reporting requirements and requirements to establish cash dominion accounts with the administrative agent, are triggered by failing to maintain availability under the New ABL Facility at or above
specified thresholds or by the existence of an event of default under the New ABL Facility. The New ABL Facility provides for some exemptions to its negative covenants allowing the Company to make certain restricted payments and investments; subject
to maintaining availability under the New ABL Facility at or above a specified threshold and the absence of a default.
The New ABL
Facility contains a minimum fixed charge coverage ratio of 1.0 to 1.0 that is triggered when availability under the New ABL Facility falls below a specified threshold and is tested until availability exceeds a separate specified threshold for 30
consecutive days.
The New ABL Facility contains events of default customary for facilities of this nature, including, but not limited,
to: (i) events of default resulting from the Borrowers failure or the failure of any credit party to comply with covenants (including the above-referenced financial covenant during periods in which the financial covenant is tested); (ii)
the occurrence of a change of control; (iii) the institution of insolvency or similar proceedings against the Borrowers or any credit party; and (iv) the occurrence of a default under any other material indebtedness the Borrowers 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 New ABL Facility, the lenders will be able to declare any outstanding principal balance of our New ABL Facility,
together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies, including remedies against the collateral, as more particularly specified in the New ABL Facility. As of March 31, 2018 the Company was in
compliance with debt covenants.
NOTE 6 Income Taxes
Our accounting Predecessor, was originally organized as a limited partnership and treated as a flow-through entity for federal and most state
income tax purposes. As such, taxable income or loss and any related tax credits were passed through to its members and were included in their tax returns. In an effort to initiate a public offering, the Company restructured, effective
February 13, 2018, and is now recognized as a corporation. Accordingly, a provision for federal and state corporate income taxes has been made only for the operations of the Company from February 13, 2018 through March 31, 2018 in the
accompanying unaudited condensed consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in
the financial statements using enacted tax rates. In connection with the IPO and related Reorganization Transactions, the Company was formed as a corporation to hold all of the operating companies of QES LP, which was subsequently renamed Quintana
Energy Services LLC. Because QES is a taxable entity, the Company established a provision for deferred income taxes as of February 13, 2018.
ASC 740,
Income Taxes
, requires the Company to reduce its deferred tax assets by a valuation allowance if, based on the
weight of the available evidence, it is more likely than not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the
periods in which those temporary differences are deductible. As a result of the evaluation of both the positive and negative evidence, the Company determined it does not believe it is more likely than not that its deferred tax assets will be
utilized in the foreseeable future and has therefore recorded a valuation allowance. The valuation allowance as of March 31, 2018 fully offsets the impact of the initial cumulative deferred tax benefit recorded related to the formation of QES.
Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and
liabilities and their reported amounts in the financial statements using enacted tax rates. The Company will adopt ASU
2015-17,
Balance Sheet Classification of Deferred Taxes
and will classify any
deferred tax assets and liabilities as noncurrent.
ASC
740-270-25,
Income Taxes Interim Reporting, requires the Company to compute its interim tax provision by applying an estimated annual effective tax rate to
ordinary income (or loss) and then computing the tax expense (or
9
benefit) related to all other items individually. The Company has incurred a year to date ordinary loss for the quarter, however, plans to be in an ordinary income position for the year. As such,
the interim period benefit shall be computed in accordance with ASC
740-270-30-5,
in which the estimated annual effective tax
rate shall be applied to the year to date ordinary income at the end of each interim period and any tax benefit as a result, shall be limited if determined the benefit will not be realized.
Total tax expense was $50,990 resulting in a negative effective tax rate of 0.3% for the quarter ended March 31, 2018. The negative
effective tax rate is primarily due to our full valuation allowance position and state tax expense, which creates a deviation from the customary relationships between income tax (expense)/benefit and
pre-tax
income/(loss).
On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (the Tax
Reform Act). The legislation significantly changed U.S. tax law by, among other things, lowering corporate income tax rates from a maximum of 35% to 21%, effective January 1, 2018, making changes to the utilization of net operating
losses, abolishing the alternate minimum tax and establishing interest expense limitations. The Company has applied the new corporate tax rate and other applicable provisions to calculate its interim tax provision. Due to anticipated future guidance
from the Internal Revenue Service, and interpretation of the changes in tax law, the amounts recorded as a result of implementation of the Tax Reform Act could be subject to change.
Tax positions are evaluated for recognition using a
more-likely-than-not
threshold, and those tax
positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The
Companys policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2018, the Company did not have any accrued liability for uncertain tax positions and does not anticipate
recognition of any significant liabilities for uncertain tax positions during the next 12 months.
NOTE 7 Related Party Transactions
The Company utilizes some Quintana affiliate employees for certain corporate functions, such as accounting and risk management. Such amounts
are reimbursed by the Company on a monthly basis.
At March 31, 2018 and December 31, 2017, QES had the following transactions
with related parties (
in thousands of dollars
):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
Accounts payable to affiliates of Quintana
|
|
$
|
39
|
|
|
$
|
81
|
|
Accounts payable to affiliates of Archer Well Company Inc.
|
|
$
|
13
|
|
|
$
|
9
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2018
|
|
|
2017
|
|
Operating expenses from affiliates of Quintana
|
|
$
|
124
|
|
|
$
|
87
|
|
Operating expenses from affiliates of Archer Well Company Inc.
|
|
$
|
4
|
|
|
$
|
|
|
NOTE 8 Business Concentration
Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents and
accounts receivable. Concentrations of credit risk with respect to accounts receivable are limited because the Company performs credit evaluations, sets credit limits and monitors the payment patterns of its customers. Cash balances on deposits with
financial institutions, at times, may exceed federally insured limits. The Company regularly monitors the institutions financial condition.
The majority of the Companys business is conducted with large, midsized, small and independent oil and gas operators E&P companies.
The Company evaluates the financial strength of customers, provides allowances for probable credit losses when deemed necessary and evaluates the market for the Companys services in the oil and gas industry in the United States, a market that
has historically experienced significant volatility.
10
As of March 31, 2018, one customers revenue represented 13.7% of the Companys
consolidated revenue. There were no customers whose revenue exceeded 10.0% of consolidated revenue for the three months ended March 31, 2017.
As of March 31, 2018, two customers had balances due that represented 14.6% and 11.2%, respectively, of the Companys consolidated
accounts receivable.
NOTE 9 Commitments and Contingencies
Environmental Regulations & Liabilities
The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for the
protection of the environment. The Company continues to monitor the status of these laws and regulations. However, the Company cannot predict the future impact of such standards and requirements on its business, which are subject to change and can
have retroactive effectiveness.
Currently, the Company has not been fined, cited or notified of any environmental violations or
liabilities that would have a material adverse effect upon its consolidated financial position, results of operations, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could
be incurred in the near term to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the
corrective actions which may be required, the determination of the Companys liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.
Litigation
The Company is a defendant or
otherwise involved in a number of lawsuits in the ordinary course of business. Estimates of the range of liability related to pending litigation are made when the Company believes the amount and range of loss can be estimated and records its best
estimate of a loss when the loss is considered probable. When a liability is probable, and there is a range of estimated loss with no best estimate in the range, the minimum estimated liability related to the lawsuits or claims is recorded. As
additional information becomes available, the potential liability related to pending litigation and claims is assessed and the estimate is revised. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may
differ from estimates. The Companys ultimate exposure with respect to pending lawsuits and claims is not expected to have a material adverse effect on our financial position, results of operations or cash flows.
A class action has been filed against one of the Companys subsidiaries alleging violations of the Fair Labor Standards Act
(FLSA) relating to
non-payment
of overtime pay. The Company believes its pay practices comply with the FLSA. The case is working its way through the various stages of the legal process, however
management believes the Companys exposure is not material.
The Company is not aware of any other matters that may have a material
effect on its financial position or results of operations.
NOTE 10 Segment Information
QES currently has four reportable business segments: Directional Drilling, Pressure Pumping, Pressure Control and Wireline. These business
segments have been selected based on the Companys chief operating decisions makers (the CODM) assessment of resource allocation and performance. The Company considers its Chief Executive Officer to be its CODM. The CODM
evaluates the performance of our business segments based on revenue and income measures, which include
non-GAAP
measures.
Directional Drilling
Our Directional
Drilling segment is comprised of directional drilling services, downhole navigational and rental tools businesses and support services, including well planning and site supervision, which assists customers in the drilling and placement of complex
directional and horizontal wellbores. This segment utilizes its fleet of
in-house
positive pulse measurement-while-drilling (MWD) navigational tools, mud motors and ancillary downhole tools,
11
as well as third-party electromagnetic (EM) navigational systems. The demand for these services tends to be influenced primarily by customer drilling-related activity levels. We
provide directional drilling and associated services to E&P companies in many of the most active areas of onshore oil and natural gas development in the United States, including the Permian Basin, Eagle Ford Shale,
Mid-Continent
region (including the SCOOP/STACK), Marcellus/Utica Shale and DJ/Powder River Basin.
Pressure
Pumping
Our Pressure Pumping segment provides hydraulic fracturing stimulation services, cementing services and acidizing services.
The majority of the revenues generated in this segment are derived from pressure pumping services focused on fracturing, cementing and acidizing services in the
Mid-Continent
and Rocky Mountains regions. These
pressure pumping and stimulation services are primarily used in the completion, production and maintenance of oil and gas wells. Customers for this segment include major E&P operators as well as independent oil and gas producers.
Pressure Control
Our Pressure Control
segment supplies a wide variety of equipment, services and expertise in support of completion and workover operations throughout the United States. Its capabilities include coiled tubing, snubbing, fluid pumping, nitrogen, well control and other
pressure control related services. Our pressure control equipment is tailored to the unconventional resources market with the ability to operate under high pressures without having to delay or cease production during completion operations. We
provide our pressure control services primarily in the
Mid-Continent
region (including the SCOOP/STACK), Eagle Ford Shale, Permian Basin, Marcellus/Utica Shale, DJ/Powder River Basin, Haynesville Shale,
Fayetteville Shale and Willinston Basins (including the Bakken Shale).
Wireline
Our Wireline segment provides new well wireline conveyed tight-shale reservoir perforating services across many of the major U.S. shale basins
and also offers a range of services such as cased-hole investigation and production logging services, conventional wireline and tubing conveyed perforating services, mechanical services and pipe recovery services. These services are offered in both
new well completions and for remedial work. The majority of the revenues generated in our Wireline segment are derived from the Permian Basin, Eagle Ford Shale,
Mid-Continent
region (including the
SCOOP/STACK), Haynesville Shale and East Texas Basin as well as in industrial and petrochemical facilities.
Segment Adjusted EBITDA
The Company views Adjusted EBITDA as an important indicator of segment performance. The Company defines Segment Adjusted EBITDA as net income
(loss) plus income taxes, net interest expense, depreciation and amortization, impairment charges, net (gain) loss on disposition of assets, stock based compensation, transaction expenses, rebranding expenses, settlement expenses, severance expenses
and equipment standup expense. The CODM uses Segment Adjusted EBITDA as the primary measure of segment operating performance.
The
following table presents a reconciliation of Segment Adjusted EBITDA to net loss (
in thousands of dollars
):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2018
|
|
|
2017
|
|
Directional Drilling
|
|
$
|
2,580
|
|
|
$
|
3,734
|
|
Pressure Pumping
|
|
|
9,889
|
|
|
|
3,693
|
|
Pressure Control
|
|
|
3,650
|
|
|
|
(260
|
)
|
Wireline
|
|
|
2,564
|
|
|
|
(1,420
|
)
|
Corporate and Other
|
|
|
(13,824
|
)
|
|
|
(4,888
|
)
|
Income tax (expense) benefit
|
|
|
(51
|
)
|
|
|
6
|
|
Interest expense
|
|
|
(10,192
|
)
|
|
|
(2,601
|
)
|
Depreciation and amortization
|
|
|
(11,078
|
)
|
|
|
(11,594
|
)
|
Gain on disposition of assets, net
|
|
|
106
|
|
|
|
1,657
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(16,356
|
)
|
|
$
|
(11,673
|
)
|
|
|
|
|
|
|
|
|
|
12
Financial information related to the Companys total assets position as of March 31,
2018 and December 31, 2017, by segment, is as follow (
in thousands of dollars
):
|
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
|
December 31,
2017
|
|
Directional Drilling
|
|
$
|
83,242
|
|
|
$
|
82,789
|
|
Pressure Pumping
|
|
|
116,579
|
|
|
|
111,322
|
|
Pressure Control
|
|
|
56,199
|
|
|
|
52,884
|
|
Wireline
|
|
|
33,627
|
|
|
|
28,988
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
289,647
|
|
|
$
|
275,983
|
|
Corporate & Other
|
|
|
9,089
|
|
|
|
7,695
|
|
Eliminations
|
|
|
(11,446
|
)
|
|
|
(8,019
|
)
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
287,290
|
|
|
$
|
275,659
|
|
|
|
|
|
|
|
|
|
|
The following tables set forth certain financial information with respect to QES reportable segments
(
in thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2018
|
|
|
|
Directional
Drilling
|
|
|
Pressure
Pumping
|
|
|
Pressure
Control
|
|
|
Wireline
|
|
|
Total
|
|
Revenues
|
|
$
|
37,602
|
|
|
$
|
53,400
|
|
|
$
|
27,961
|
|
|
$
|
22,305
|
|
|
$
|
141,268
|
|
Depreciation and amortization
|
|
|
2,607
|
|
|
|
5,536
|
|
|
|
1,913
|
|
|
|
1,022
|
|
|
|
11,078
|
|
Capital expenditures
|
|
$
|
2,708
|
|
|
$
|
3,502
|
|
|
$
|
4,380
|
|
|
$
|
115
|
|
|
$
|
10,705
|
|
|
|
|
|
Three Months Ended March 31, 2017
|
|
|
|
Directional
Drilling
|
|
|
Pressure
Pumping
|
|
|
Pressure
Control
|
|
|
Wireline
|
|
|
Total
|
|
Revenues
|
|
$
|
31,149
|
|
|
$
|
26,503
|
|
|
$
|
18,524
|
|
|
$
|
9,263
|
|
|
$
|
85,439
|
|
Depreciation and amortization
|
|
|
3,226
|
|
|
|
5,755
|
|
|
|
1,518
|
|
|
|
1,095
|
|
|
|
11,594
|
|
Capital expenditures
|
|
$
|
2,074
|
|
|
$
|
1,215
|
|
|
$
|
918
|
|
|
$
|
5
|
|
|
$
|
4,212
|
|
NOTE 11 Revenue from Contracts with Customers
In adopting ASC 606, the Companys revenue recognition model largely aligns with its historical revenue recognition pattern. Immaterial
differences may exist for contracts with initial mobilization and demobilization charges. We determined that the adoption of this standard did not have a material impact on our retained earnings at the beginning of the fiscal year 2018, our
statement of operations or statement of cash flows.
The Company has also exercised the following practical expedients and accounting
policy elections provided by ASC 606 for all its service contracts.
|
1)
|
QES occasionally pays commissions to its sales staff for successfully obtaining a contract. The commission
payment is incremental costs of obtaining a contract and should be capitalized and amortized over the
|
13
|
contract period. However, ASC
340-40-25-4
provides a practical expedient,
which states that an entity may recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that the entity otherwise would have recognized is one year or less. Management
has elected to use this practical expedient as most of the Companys service contracts are less than a month. Accordingly, the Company expenses the commission expense as incurred.
|
|
2)
|
In May 2016, the FASB issued ASU
2016-12
that allows an entity to make
an accounting policy election to exclude from the transaction price certain types of taxes collected from a customer (i.e., present revenue net of these taxes), including sales, use, value-added and some excise taxes.
|
Typical Contractual Arrangements
The
Company typically provides the services based upon a combination of a Master Service Agreement (MSA) or its General Terms & Conditions (T&Cs) and a purchase order or other similar forms of work requests that primarily
operate on a spot market basis for a defined work scope on a particular well or well pad. Services are provided based on a price book and bid on a day rate, stage rate or job basis. QES may also charge for the mobilization and
set-up
of equipment and for materials and consumables used in the services. Contracts generally are short-term in nature, ranging from a few hours to multiple weeks. Contracts typically do not stipulate substantive
early termination penalties for either party. As such, the Company determined that its contracts are day to day, even though parties typically do not terminate the contract early during the normal course of business. In cases where the customer
terminates the contract early, the Company has an enforceable right to payment for services performed to date. Under dayrate contracts, we generally receive a contractual dayrate for each day we are performing services. The contractual dayrate may
vary based on the status of the operations and generally includes a full operating rate and a standby rate. Other fees may be stipulated in the contract related to mobilization and setup of equipment and reimbursements for consumables and cost of
tools and equipment, that are involuntarily damaged or
lost-in-hole.
Performance Obligations and Transaction Price
Customers generally contract with us to provide an integrated service of personnel and equipment for directional drilling, pressure pumping,
pressure control or wireline services. The Company is seen by the operator as the overseer of its services and is compensated to provide an entire suite for its scope of services. QES determined that each service contract contains a single
performance obligation, which is each days service. In addition, each days service is within the scope of the series guidance as both criteria of series guidance are met: 1) each distinct increment of service (i.e., days available to
supervise or number of stages determined at contract inception) that the Company agrees to transfer represents a performance obligation that meets the criteria for recognizing revenue over time, and 2) the Company would use the same method for
measuring progress toward satisfaction of the performance obligation for each distinct increment of service in the series. Therefore, the Company has determined that each service contract contains one single performance obligation, which is the
series of each distinct stage or days service.
The transaction price for the Companys service contracts is based on the
amount of consideration the Company expects to receive for providing the services over the specified term and includes both fixed amounts and unconstrained variable amounts. In addition, the contract term may impact the determination and allocation
of the transaction price and recognition of revenue. As the Companys contracts do not stipulate substantive termination penalties, the contract is treated as day to day. Typically, the only fixed or known consideration at contract inception is
initial mobilization and demobilization (where it is contractually guaranteed). In cases where the demobilization fee is not fixed, the Company estimates the variable consideration using the expected value method and includes this in the transaction
price to the extent it is not constrained. Variable consideration is generally constrained if it is probable that a significant reversal in the amount of cumulative revenue recognized will occur when the uncertainty associated with the variable
consideration is subsequently resolved. As the contracts are not enforceable, the contract price should not include any estimation for the dayrate or stage rate charges.
Recognition of Revenue
Directional
drilling, pressure pumping, pressure control and wireline services are consumed as the services are performed and generally enhance a well site for which the customer or operator owns the rights to. Work performed
14
on a well site does not create an asset with an alternative use to the contractor since the well/asset being worked on is owned by the customer. Therefore, the Companys measure of progress
for our contracts are hours available to provide the services over the contracted duration. This unit of measure is representative of an output method as described in ASC 606.
The following chart details the types of fees found in a typical service contract and the related recognition method under ASC 606:
|
|
|
Fee type
|
|
Revenue Recognition
|
Dayrate
|
|
Revenue is recognized based on the dayrates earned as it relates to the level of service provided for each day
throughout the contract.
|
Initial mobilization
|
|
Revenue is estimated at contract inception and included in the transaction price to be recognized ratably over contract
term.
|
Demobilization
|
|
Unconstrained demobilization revenue is estimated at contract inception, included in the transaction price, and
recognized ratably over the contract term.
|
Reimbursement
|
|
Recognized (gross of costs incurred) at the amount billed to the customer.
|
Disaggregation of Revenue
The Company disaggregated revenue by major service line. The table below is a reconciliation of the disaggregated revenue with the reported
results (
in thousands of dollars
):
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31,
|
|
|
Year ended
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
(
In
thousands
)
|
|
Directional Drilling
|
|
$
|
37,602
|
|
|
$
|
145,230
|
|
Pressure Pumping
|
|
|
53,400
|
|
|
|
153,118
|
|
Pressure Control
|
|
|
27,961
|
|
|
|
89,912
|
|
Wireline
|
|
|
22,305
|
|
|
|
49,773
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
141,268
|
|
|
$
|
438,033
|
|
|
|
|
|
|
|
|
|
|
Future Performance Obligations and Financing Arrangements
As our contracts are day to day and short-term in nature, the Company determined that it does not have material future performance obligations
or financing arrangements under its service contracts. Payments are typically due within 30 days after the services are rendered. The timing between the recognition of revenue and receipt of payment is not significant.
No contract assets or liabilities were recognized related to contracts with our customers.
NOTE 12 Share-Based Compensation
Our executive officers and certain other key employees were previously granted phantom units, which is an award of common units representing
membership interest in our accounting Predecessor, with no exercise price. Each unit represents the right to receive, at the end of a stipulated period, one unrestricted membership unit with no exercise price, subject to the terms of the applicable
phantom unit agreement. Full vesting of the units was based on dual vesting components. The first was the time vesting component and the second component required the consummation of a specified transaction, which was met upon the completion of the
Companys IPO. All grants of phantom units converted to an equivalent grant of Restricted Stock Units (RSUs) in QES following the IPO.
15
The Company recognized $9.9 million in equity based compensation in the three months ended
March 31, 2018. As of March 31, 2018 and 2017, total unamortized compensation costs related to unvested RSU awards were $18.4 million and $27.7 million, respectively.
2015 Grant
During 2015,
5.8 million phantom units were awarded to executive officers and other key employees. These phantom units time vested as of December 31, 2015, and all 5.8 million phantom units remained outstanding as of December 31, 2017. As of
February 13, 2018, upon the consummation of the Companys IPO, these phantom units fully vested as common shares in QES. Each 31.669363 phantom units were then converted to one common share in QES.
2017 Grant
In 2017, the
Company awarded approximately 46.3 million phantom units to executive officers and other key employees. These phantom units required a specified transaction as a performance component and a time vesting component spread equally over four years.
As of December 31, 2017, 45.8 million phantom units remained outstanding, none of which had fully vested. As of February 13, 2018, on the consummation of the Companys IPO, the phantom units partially vested as the IPO satisfied
the grants performance requirement. Also following the IPO, the right of each phantom unit to be exchanged for an interest in QES LP converted to an equivalent right to RSUs in QES and each 31.669363 phantom unit converted to one RSU in QES.
On February 28, 2018, the majority of the 2017 grants reached their first anniversary and 352,651 shares time vested.
The grant
agreements with each executive officer and key employees calls for each phantom unit to be settled for one share in QES unless the board of directors of the Company, in its discretion, elects to pay an amount of cash equal to the fair market value
of a share on the full vesting date.
2018 Grant
In April, 2018, the Company awarded 951,270 restricted stock units to its directors and employees under the Companys 2018 Long-Term
Incentive Plan. Each restricted stock unit represents the contingent right to receive one share of QES common stock.
All restricted stock
units awarded to
non-employee
Company directors include a time vesting element with each grant vesting on the first anniversary of the Companys IPO (Director RSUs). In total, our
non-employee
directors were granted 57,145 Director RSUs.
All restricted stock units awarded to
employees include a time vesting element, with each grant vesting in equal parts over a
3-year
period on the anniversary of the Companys IPO. The restricted stock units awarded to employees are divided
into two categories: (1) restricted stock units with time vesting only (RSUs) and (2) restricted stock units with a performance requirement and time vesting requirements (PSUs).
The RSUs will vest in equal
one-third
installments on the first three anniversaries of the
Companys IPO, in each case, so long as the grantee remains continuously employed by the Company from the grant date through each applicable vesting date. In total, we granted 476,542 RSUs to employees.
The PSUs require the achievement of a certain performance as measured on December 31, 2018, based on (i) the Companys
performance with respect to relative total stockholder return and (ii) the Companys performance with respect to absolute total stockholder return. Any PSUs that have not been earned at the end of a performance period are forfeited. Should
the grantee satisfy the service requirement applicable to such earned performance share unit, vesting shall occur in equal installments on the first three anniversaries of the Companys IPO. In total, we granted 417,583 PSUs to employees.
16
A summary of the status and changes during the three months ended March 31, 2018 of the
Companys shares of
non-vested
RSUs is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
(in thousands)
|
|
|
Grant Date Fair
Value per Share
|
|
|
Weighted Average
Remaining Life
(in years)
|
|
Outstanding at December 31, 2017
|
|
|
1,627
|
|
|
$
|
17.73
|
|
|
|
3.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
Expired
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
(535
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2018
|
|
|
1,092
|
|
|
$
|
17.73
|
|
|
|
3.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 13 Loss Per Share
Basic loss per share (EPS) is based on the weighted average number of common shares outstanding during the period. A reconciliation
of the number of shares used for the basic EPS computation is as follows (
in thousands, except per share amounts
):
|
|
|
|
|
|
|
As of March 31,
2018
|
|
Numerator:
|
|
|
|
|
Net loss attributed to common share holders
|
|
$
|
(14,810
|
)
|
|
|
|
|
|
Denominator:
|
|
|
|
|
Weighted average common shares outstanding - basic
|
|
|
33,318
|
|
Weighted average common shares outstanding - diluted
|
|
|
33,318
|
|
|
|
|
|
|
Net loss per common share:
|
|
|
|
|
Basic
|
|
$
|
(0.44
|
)
|
|
|
|
|
|
Diluted
|
|
$
|
(0.44
|
)
|
|
|
|
|
|
The Company has issued 1,092 potentially dilutive shares of RSUs. However, the Company did not include these
RSUs in its calculation of diluted loss per share for the period presented, because to include them would be anti-dilutive.
NOTE
14-
Subsequent Events
The Company evaluates events that occur after the balance sheet date but
before the financial statements are issued for potential recognition or disclosure. Based on the evaluation, the Company determined that there were no material subsequent events for recognition or disclosure other than those disclosed herein.
17
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form
10-Q
for the quarterly period ended March 31, 2018 (this
Quarterly Report) contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly
Report, 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 Quarterly Report, 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 described under the heading Risk Factors included in this Quarterly Report and our most recent Annual
Report on Form
10-K
for the fiscal year ended December 31, 2017. These forward-looking statements are based on managements current beliefs, based on currently available information, as to the
outcome and timing of future events.
Forward-looking statements may include statements about
|
|
|
our operating cash flows, the availability of capital and our liquidity;
|
|
|
|
our future revenue, income and operating performance;
|
|
|
|
uncertainty regarding our future operating results;
|
|
|
|
our ability to sustain and improve our utilization, revenue 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;
|
|
|
|
loss or corruption of our information in a cyberattack on our computer systems;
|
|
|
|
the supply and demand for oil and natural gas;
|
|
|
|
the ability of our customers to obtain capital or financing needed for exploration and production
(E&P) operations;
|
|
|
|
leasehold or business acquisitions;
|
|
|
|
general economic conditions;
|
|
|
|
the occurrence of a significant event or adverse claim in excess of the insurance we maintain;
|
|
|
|
seasonal and adverse weather conditions that can affect oil and natural gas operations;
|
18
|
|
|
our ability to successfully develop our research and technology capabilities and implement technological
developments and enhancements; and
|
|
|
|
plans, objectives, expectations and intentions contained in this Quarterly 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, decline in demand for our services, the cyclical nature and volatility of the oil and natural gas industry, a decline in, or substantial
volatility of, crude oil and natural gas commodity prices, environmental risks, regulatory changes, the inability to comply with the financial and other covenants and metrics in our New ABL Facility (as defined below), cash flow and access to
capital, the timing of development expenditures and the other risks described under Risk Factors set forth in our Annual Report on Form
10-K
for the fiscal year ended December 31, 2017. For
more information on our New ABL Facility, please see Managements Discussion and Analysis of Financial Condition and Results of OperationsOur New ABL Facility.
Should one or more of the risks or uncertainties described in this Quarterly Report or any other risks or uncertainties of which we are
currently unaware 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 Quarterly Report 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 Quarterly Report.
19
Item 2.
|
Managements Discussion and Analysis of Financial Condition and Results of Operations.
|
The following discussion and analysis should be read in conjunction with the historical consolidated financial statements and related notes
included elsewhere in this Quarterly Report on Form
10-Q
(Quarterly Report). This discussion contains forward-looking statements reflecting our current expectations and 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, including those discussed in the sections entitled Risk Factors and Cautionary Note Regarding Forward-Looking Statements appearing elsewhere in this Quarterly Report.
Overview
We are a growth-oriented
provider of diversified oilfield services to leading onshore oil and natural gas exploration and production (E&P) companies operating in conventional and unconventional plays in all of the active major basins throughout the United
States. We classify the services we provide into four reportable business segments: (1) Directional Drilling, (2) Pressure Pumping, (3) Pressure Control and (4) Wireline. Our Directional Drilling segment enables efficient
drilling and guidance of the horizontal section of a wellbore using our technologically-advanced fleet of downhole motors and 115 measurement while-drilling (MWD) kits. Our Pressure Pumping segment includes hydraulic fracturing,
cementing and acidizing services, and such services are supported by a high-quality pressure pumping fleet of 237,475 hydraulic horsepower (HHP) as of March 31, 2018. Our primary pressure pumping focus is on large hydraulic
fracturing jobs. Our Pressure Control segment provide various forms of well control, form completions and workover applications through our 23 coiled tubing units, 36
rig-assisted
snubbing units and ancillary
equipment. As of March 31, 2018, our wireline services included 47 wireline units providing a full range of pump-down services in support of unconventional completions, and cased-hole wireline services enabling reservoir characterization.
The Company was incorporated on April 13, 2017 and does not have historical financial operating results. This Quarterly Report includes
the results of our accounting Predecessor, Quintana Energy Services LP (QES LP or our Predecessor), which was formed as a Delaware partnership on November 3, 2014. In connection with our initial public offering (the
IPO), we became the holding company for QES LP and its subsidiaries.
How We Generate Revenue and the Costs of Conducting Our Business
Our core businesses depend on our customers willingness to make expenditures to produce, develop and explore for oil and gas in
the United States. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and gas, domestic and worldwide economic conditions, political instability in oil producing countries and merger and divestiture
activity among oil and gas producers. The volatility of the oil and gas industry and the consequent impact on E&P activity, could adversely impact the level of drilling, completion and workover activity by some of our customers. This volatility
affects the demand for our services and the price of our services.
We derive a majority of our revenues from services supporting oil and
gas operations. As oil and gas prices fluctuate significantly, demand for our services changes correspondingly as our customers must balance expenditures for drilling and completion services against their available cash flows. Because our services
are required to support drilling and completions activities, we are also subject to changes in spending by our customers as oil and gas prices increase or decrease.
Demand for our services has continued to improve since May 2016 as oil and natural gas prices have increased from previous levels and as the
Baker Hughes Incorporated (Baker Hughes) lower 48 U.S. states land rig count has increased from 375 rigs on May 27, 2016 to 1,007 rigs as of May 4, 2018. Although our industry experienced a significant downturn beginning in late
2014 and remained depressed for a prolonged period, which materially adversely affected our results in 2015 and 2016, the rebound in demand and increasing rig count beginning in May 2016 has improved both activity levels and pricing for our
services. Our revenue has increased each quarter from the quarter ended June 30, 2016 through the quarter ended March 31, 2018. From the second quarter of 2016 through the first quarter of 2018, our Directional Drilling business segment
increased the number of days we provided services to rigs and earned revenues during the period, including days that standby revenues were earned (rig
20
days) by 160.1%, while dayrates have improved from the lows we experienced during the second quarter of 2016.
1
We reactivated our second
and third Pressure Pumping frac fleets in February and October 2017, respectively, and our frac utilization was approaching full utilization for our active fleets at March 31, 2018. In addition we placed initial orders in January 2018 for
twelve incremental pumps for an additional 30,000 HHP and ancillary equipment to redeploy our fourth Pressure Pumping fleet. We expect to mobilize our fourth frac fleet to the field in June 2018. Utilization of our Pressure Control and Wireline
assets has also continued to improve since the second quarter of 2016.
Directional Drilling
: Our Directional Drilling business
segment provides the highly technical and essential services of guiding horizontal and directional drilling operations for E&P companies. We offer premium drilling services including directional drilling, horizontal drilling, underbalanced
drilling, measurement-while-drilling (MWD), rental tools and pipe inspection services. Our package also offers various technologies, including our positive pulse MWD navigational tool asset fleet, mud motors and ancillary downhole tools,
as well as third-party electromagnetic navigational systems. We also provide a suite of integrated and related services, including downhole rental tools and third-party inspection services of drill pipe and downhole tools. We generally provide
directional drilling services on a dayrate or hourly basis. We charge prevailing market prices for the services provided in this business segment, and we may also charge fees for set up and mobilization of equipment depending on the job. Generally,
these fees and other charges vary by location and depend on the equipment and personnel required for the job and the market conditions in the region in which the services are performed. In addition to fees that are charged during periods of active
directional drilling, a
stand-by
fee is typically agreed upon in advance and charged on an hourly basis during periods when drilling must be temporarily ceased while other
on-site
activity is conducted at the direction of the operator or another service provider. We will also charge customers for the additional cost of oilfield downhole tools and rental equipment that is
involuntarily damaged or
lost-in-hole.
Proceeds from customers for the cost of oilfield downhole tools and other equipment that is involuntarily damaged or
lost-in-hole
are reflected as product revenues.
Although we do
not typically enter into long-term contracts for our services in this business segment, we have long standing relationships with our customers in this business segment and believe they will continue to utilize our services. As of the quarter ended
March 31, 2018, 90% of our directional drilling activity is tied to
follow-me
rigs, which involve
non-contractual,
generally recurring services as our
Directional Drilling team members follow a drilling rig from
well-to-well
or
pad-to-pad
for multiple wells, and in some cases, multiple years. With increasing use of pad drilling and reactivation of rigs, through the first quarter of 2018 we have increased the number of follow me rigs from approximately 30 in the first
quarter of 2016 to 50 as of March 31, 2018. We intend to continue to
re-deploy
additional MWD kits over the course of 2018, as market conditions warrant.
Our Directional Drilling business segment accounted for approximately 26.6% and 36.5% of our revenues for the three months ended
March 31, 2018 and 2017, respectively.
Pressure Pumping
: Our Pressure Pumping business segment provides pressure pumping
services including hydraulic fracturing stimulation, cementing and acidizing services. The majority of the revenues generated in this segment are derived from pressure pumping services in the
Mid-Continent
and
Rocky Mountain regions.
Our Pressure Pumping services are based upon a purchase order, contract or on a spot market basis. Services are
bid on a stage rate or job basis (for fracturing services) or job basis (for cementing and acidizing services), contracted or hourly basis. Jobs for these services are typically short-term in nature and range from a few hours to multiple days.
Customers are charged for the services performed on location and mobilization of the equipment to the location. Additional revenue can be generated through product sales of some materials that are delivered as part of the service being performed.
Our Pressure Pumping business segment accounted for approximately 37.8% and 31.0% of our revenues for the three months ended
March 31, 2018 and 2017, respectively.
21
Pressure Control:
Our Pressure Control business segment provides a wide scope of pressure
control services, including, coiled tubing, rig assisted snubbing, nitrogen, fluid pumping and well control services.
Our coiled tubing
units are used in the provision of well-servicing and workover applications, or in support of unconventional completions. Our
rig-assisted
snubbing units are used in conjunction with a workover rig to insert
or remove downhole tools or in support of other well services while maintaining pressure in the well, or in support of unconventional completions. Our nitrogen pumping units provide a
non-combustible
environment downhole and are used in support of other pressure control or well-servicing applications.
Jobs for our pressure control
services are typically short-term in nature and range from a few hours to multiple days. Customers are charged for the services performed and any related materials (such as friction reducers and nitrogen materials) used during the course of the
services, which are reported as product sales. We may also charge for the mobilization and
set-up
of equipment, the personnel on the job, any additional equipment used on the job and other miscellaneous
materials.
Our Pressure Control business segment accounted for approximately 19.8% and 21.7% of our revenues for the three months ended
March 31, 2018 and 2017, respectively.
Wireline:
Our Wireline business segment principally works in connection with hydraulic
fracturing services in the form of pump-down services for setting plugs between frac stages, as well as with the deployment of perforation equipment in connection with
plug-and-perf
operations. We offer a full range of other pump-down and cased-hole wireline services. We also provide cased-hole production logging services,
injection profiling, stimulation performance evaluation and water break-through identification via this segment. In addition, we provide industrial logging services for cavern, storage and injection wells.
We provide our wireline services on a spot market basis or subject to a negotiated pricing agreement. Jobs for these services are typically
short-term in nature, lasting anywhere from a few hours to a few weeks. We typically charge the customer for these services on a per job basis at agreed-upon spot market rates. Our Wireline segment accounted for approximately 15.8% and 10.8% of our
revenues for the three months ended March 31, 2018 and 2017, respectively.
How We Evaluate Our Operations
Our management team utilizes a number of measures to evaluate the results of operations and efficiently allocate personnel, equipment and
capital resources. We evaluate our business segments primarily by asset utilization, revenue and Adjusted EBITDA.
Adjusted EBITDA is not
a measure of net income or cash flows as determined by U.S. generally accepted accounting principles (GAAP). We define Adjusted EBITDA as net income (loss) plus income taxes, net interest expense, depreciation and amortization,
impairment charges, net (gain)/loss on disposition of assets, stock based compensation, transaction expenses, rebranding expenses, settlement expenses, severance expenses and equipment standup expense.
Adjusted EBITDA is a supplemental
non-GAAP
financial measure that is used by management and external
users of our financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP.
We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of
our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company 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 income as
determined in accordance with GAAP, or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a companys financial performance, such as a
companys cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled
22
measures of other companies. For a definition and description of Adjusted EBITDA and reconciliations of Adjusted EBITDA to net income, the most directly comparable financial measure calculated
and presented in accordance with GAAP, please see Adjusted EBITDA below.
Items Affecting the Comparability of our Future Results
of Operations to our Historical Results of Operations
The historical financial results of our Predecessor discussed below
may not be comparable to our future financial results for the reasons described below.
|
|
|
Over the course of the first quarter of 2017 we sold select wireline and pressure pumping assets for aggregate
sale proceeds of $27.6 million. While we expect continued growth, expansions and strategic divestitures in the future, it is likely such growth, expansions and divestitures will be economically different from the acquisitions and divestitures
discussed above, and such differences in economics will impact the comparability of our future results of operations to our historical results.
|
|
|
|
QES is subject to U.S. federal and state income taxes as a corporation. Our Predecessor, was treated as a
flow-through entity for U.S. federal income tax purposes, and as such, was generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to its taxable income was passed through to its partners.
Accordingly, the financial data attributable to our Predecessor contains no expense for U.S. federal income taxes or income taxes in any state or locality (other than franchise tax in the State of Texas). We estimate we will be subject to U.S.
federal, state and local taxes at a blended statutory rate of 22.3% of
pre-tax
earnings.
|
|
|
|
As of March 31, 2018, we had actual outstanding indebtedness of $13.0 million.
|
|
|
|
Our IPO served as a vesting event under the phantom unit awards granted under our long-term incentive plans.
As a result, certain of our phantom unit awards fully vested and were settled in connection with the IPO and additional phantom unit awards will fully vest and be settled according to their vesting schedules. We recognized $9.9 million of share
based compensation expense during the first quarter of 2018. Expense associated with these phantom unit awards were recognized in the first quarter of 2018. See Executive CompensationQES LP Phantom Units in our 2017 Annual Report
on Form
10-K
for additional detail on our phantom unit awards and our incentive plans.
|
|
|
|
As we further implement controls, processes and infrastructure applicable to companies with publicly traded
equity securities, it is likely that we will incur additional selling, general and administrative (SG&A), expenses relative to historical periods.
|
Our future results will depend on our ability to efficiently manage our combined operations and execute our business strategy.
Recent Trends and Outlook
Demand
for our services is predominately influenced by the level of drilling and completion activity by E&P companies, which is driven largely by the current and anticipated profitability of developing oil and natural gas reserves. Crude oil prices
have increased from their lows of $26.21 per barrel (Bbl) in early 2016 to $70.74 per Bbl as of May 7, 2018 (based on the West Texas Intermediate Spot Oil Price, or WTI), but remain 52% lower than a high of $107.26 per Bbl in
June 2014. Natural gas prices have increased from their lows of $1.64 per million British Thermal Units (MMBtu) in early 2016 to $2.08 per MMBtu as of May 7, 2018, but remain 292% lower than a high of $8.15 per MMBtu in February 2014.
Drilling and completion activity in the United States has increased significantly as commodity prices have generally increased, which we believe will correspond with increased demand for our services.
We view the horizontal rig count as a reliable indicator of the overall level of demand for our services. According to Baker Hughes,
horizontal rigs accounted for 88.5% of all total active rigs in the United States as of May 4, 2018, as compared to only 28.0% a decade earlier. Horizontal drilling allows E&P companies to drill wells with greater exposure to the economic
payzone of a targeted formation, thus improving production. The advantages of horizontal drilling have increasingly led to greater demand for high-specification rigs that are more efficient in drilling shale oil
23
and natural gas wells than older drilling rigs. Additionally, high-specification rigs which are capable of pad drilling operations have become more prevalent in North America and enable the
operator to drill more wells per rig per year than older rigs. We believe that the increase in horizontal rigs and increased demand for high-specification rigs will drive demand for our experienced directional drilling personnel and modern
equipment.
Completion of horizontal wells has evolved to require increasingly longer laterals and more hydraulic fracturing stages per
horizontal well, which increase the exposure of the wellbore to the reservoir and improve production of the well. Hydraulic fracturing operations are conducted via a number of discrete stages along the lateral section of the wellbore. As wellbore
lengths have increased, the number of hydraulic fracturing stages has continued to rise. According to Spears & Associates, from 2014 to 2016 the average number of stages per horizontal well increased from 23 stages per well to 34 stages per
well, and is expected to further increase to an average of 48 stages per horizontal well in 2018. The market has also trended toward larger scale hydraulic fracturing operations, characterized by more hydraulic horsepower (HHP) per well.
This requires a greater number of hydraulic fracturing units per fleet to execute a completion job. These trends, along with the overall expected recovery of U.S. drilling and completion activity, favor continued growth of the hydraulic fracturing
sector. Spears & Associates forecasts that U.S. demand for HHP is expected to increase more than 112% from the fourth quarter of 2016 to the fourth quarter of 2018. As a result, we expect demand for our pressure pumping services to expand,
including needs for our hydraulic fracturing and acidizing services.
Demand for our pressure control services is expected to grow along
with increases in drilling and completion activity and benefit from the increasing average age of producing oil and natural gas wells. We believe that maintenance of unconventional wells will drive demand for our
rig-assisted
snubbing, nitrogen and fluid pumping units.
The markets we serve, and the oilfield
services market in general, are characterized by fragmentation and consist of a large number of small independent operators serving these markets. We believe our relative scale is a differentiator, as we are a leading independent provider of
directional drilling and pressure control services and have significant scale in both our pressure pumping and wireline services.
We are
well positioned for the ongoing recovery we are observing in each of our service lines, all of which have already realized pricing improvement from the lows observed in 2016.
While we believe these trends will benefit us, our markets may be adversely affected by industry conditions that are beyond our control. For
example, the overall decline in oil prices from their high levels in 2014 to their low levels in 2016 and the uncertainty regarding the sustainability of current oil prices has materially affected and may continue to materially affect the demand for
our services and the rates that we are able to charge. Additionally, adverse weather conditions can affect the drilling and completion activities of our customers. During periods of heavy snow, high winds, ice or rain, the logistical capabilities of
our suppliers may be delayed or we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. For example, inclement weather including freezing temperatures and high winds affected
our available revenue generating hours in the first quarter of 2018.
The industry continues to face strain in logistics, vendor service
quality and delivery times across various aspects of the third party supply chain, driven by continued growth in demand. We are proactively managing these transitory issues facing the entire industry to limit the impact to our customers and
business. In addition, continued tightening of the labor market could result in higher wage rates, as well as increased recruiting, hiring, onboarding and training costs.
24
Results of Operations
The following tables provide selected operating data for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31, 2018
|
|
|
March 31, 2017
|
|
|
|
(Unaudited)
|
|
Revenues:
|
|
$
|
141,268
|
|
|
$
|
85,439
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
106,492
|
|
|
|
66,836
|
|
General and administrative expenses
|
|
|
29,917
|
|
|
|
17,744
|
|
Depreciation and amortization
|
|
|
11,078
|
|
|
|
11,594
|
|
Gain on disposition of assets
|
|
|
(106
|
)
|
|
|
(1,657
|
)
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(6,113
|
)
|
|
|
(9,078
|
)
|
Interest expense, net
|
|
|
(10,192
|
)
|
|
|
(2,601
|
)
|
|
|
|
|
|
|
|
|
|
Loss before tax
|
|
|
(16,305
|
)
|
|
|
(11,679
|
)
|
Income tax (expense) benefit
|
|
|
(51
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
Net Loss
|
|
$
|
(16,356
|
)
|
|
$
|
(11,673
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31, 2018
|
|
|
March 31, 2017
|
|
|
|
(Unaudited)
|
|
Segment Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
Directional Drilling
|
|
$
|
2,580
|
|
|
$
|
3,734
|
|
Pressure Pumping
|
|
|
9,889
|
|
|
|
3,693
|
|
Pressure Control
|
|
|
3,650
|
|
|
|
(260
|
)
|
Wireline
|
|
|
2,564
|
|
|
|
(1,420
|
)
|
Adjusted EBITDA(1)
|
|
$
|
15,483
|
|
|
$
|
3,972
|
|
|
|
|
Other Operational Data:
|
|
|
|
|
|
|
|
|
Directional Drilling rig days (2)
|
|
|
3,706
|
|
|
|
3,231
|
|
Average monthly Directional Drilling rigs on revenue (3)
|
|
|
57
|
|
|
|
55
|
|
Total hydraulic fracturing stages
|
|
|
963
|
|
|
|
586
|
|
Average hydraulic fracturing revenue per stage
|
|
$
|
52,477
|
|
|
$
|
42,138
|
|
(1)
|
Adjusted EBITDA is a supplemental
non-GAAP
financial measure that is
used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. For a definition and description of Adjusted EBITDA and reconciliations of Adjusted EBITDA to net income, the most
directly comparable financial measure calculated and presented in accordance with GAAP, please read Adjusted EBITDA below.
|
(2)
|
Rig days represent the number of days we are providing services to rigs and are earning revenues during the
period, including days that standby revenues are earned.
|
(3)
|
Rigs on revenue represents the number of rigs earning revenues during a time period, including days that
standby revenues are earned.
|
25
Adjusted EBITDA
Adjusted EBITDA is a supplemental
non-GAAP
financial measure that is used by management and external
users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
Adjusted EBITDA is not a measure of
net income or cash flows as determined by GAAP. We define Adjusted EBITDA as net income (loss) plus income taxes, net interest expense, depreciation and amortization, impairment charges, net (gain)/loss on disposition of assets, stock based
compensation, transaction expenses, rebranding expenses, settlement expenses, severance expenses and equipment standup expense.
We
believe Adjusted EBITDA margin is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We
exclude the items listed above in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company 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 income as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity. Certain items
excluded from Adjusted EBITDA are significant components in understanding and assessing a companys financial performance, such as a companys cost of capital and tax structure, as well as the historic costs of depreciable assets, none of
which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of the
non-GAAP
financial measures of Adjusted EBITDA to
the most directly comparable GAAP financial measure for the three months ended March 31, 2018 and 2017 (
in thousands of dollars
):
2
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2018
|
|
|
2017
|
|
Adjustments to reconcile Adjusted EBITDA to net loss:
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(16,356
|
)
|
|
$
|
(11,673
|
)
|
Income tax expense (benefit)
|
|
|
51
|
|
|
|
(6
|
)
|
Interest expense, net
|
|
|
10,192
|
|
|
|
2,601
|
|
Depreciation and amortization expense
|
|
|
11,078
|
|
|
|
11,594
|
|
Gain on disposition of assets, net
|
|
|
(106
|
)
|
|
|
(1,657
|
)
|
Non-cash
stock based compensation
|
|
|
9,886
|
|
|
|
|
|
Rebranding expense
(1)
|
|
|
|
|
|
|
1
|
|
Settlement expense
(2)
|
|
|
223
|
|
|
|
1,439
|
|
Severance expense
(3)
|
|
|
|
|
|
|
182
|
|
Equipment and standup expense
(4)
|
|
|
515
|
|
|
|
1,491
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
15,483
|
|
|
$
|
3,972
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Relates to expenses incurred in connection with rebranding our business segments in 2017.
|
26
(2)
|
For 2017, represents professional fees related to investment banking, accounting and legal services associated
with entering into the Former Term Loan that were recorded in general and administrative expenses. For 2018, represents lease buyouts, legal FLSA and settlements costs, facility closures and other
non-recurring
expenses that were recorded in general and administrative expenses.
|
(3)
|
Relates to severance expenses in 2017 incurred in connection with a program implemented to reduce head count
in connection with the industry downturn. In our actual performance for the three months ended March 31, 2018 and 2017, $0.0 and $0.1 million was recorded in direct operating expenses, respectively, and the remainder was recorded in
general and administrative expenses.
|
(4)
|
Relates to equipment standup costs incurred in connection with the mobilization and redeployment of assets. In
our actual performance for the three months ended March 31, 2018, approximately $0.4 million was recorded in direct operating expenses and approximately $0.1 million was recorded in general and administration expenses. In our actual
performance for the three months ended March 31, 2017, approximately $1.5 million was recorded in direct operating expenses and $0.0 was recorded in general and administration expenses.
|
Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017
Revenue. The following table provides our revenues by business segment for the periods indicated (in
thousands of dollars)
:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2018
|
|
|
2017
|
|
Revenue:
|
|
|
|
|
|
|
|
|
Directional Drilling
|
|
$
|
37,602
|
|
|
$
|
31,149
|
|
Pressure Pumping
|
|
|
53,400
|
|
|
|
26,503
|
|
Pressure Control
|
|
|
27,961
|
|
|
|
18,524
|
|
Wireline
|
|
|
22,305
|
|
|
|
9,263
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
141,268
|
|
|
$
|
85,439
|
|
|
|
|
|
|
|
|
|
|
Revenue for the three months ended March 31, 2018 increased by $55.8 million, or 65.3%, to
$141.3 million from $85.4 million for the three months ended March 31, 2017. The increase in revenue by business segment was as follows:
Directional Drilling
revenue increased by $6.5 million, or 20.9%, to $37.6 million for the three months ended
March 31, 2018, from $31.1 million for the three months ended March 31, 2017. This increase was primarily attributable to a 15.7% increase in utilization and a 3.9% increase in our dayrate to $9,434. Approximately 93.0% of our
Directional Drilling business segment revenue was derived from directional drilling and MWD activities for the three months ended March 31, 2018 compared to 94.2% for the three months ended March 31, 2017. The change in utilization and
pricing accounted for 76.6% and 23.4% of the Directional Drilling revenue increase, respectively.
Pressure Pumping
revenue increased by $26.9 million, or 101.5%, to $53.4 million for the three months ended March 31, 2018, from $26.5 million for three months ended March 31, 2017. This increase was primarily attributable to the
mobilization of additional frac spreads in February 2017 and October 2017, which drove a 62.8% increase in stages to 963 for the three months ended March 31, 2018. Additionally we experienced a 25.7% increase in average revenue per stage to
$52,972 for the three months ended March 31, 2018, from $42,138 for the three months ended March 31, 2017, due to improving market conditions and shift in the job types completed. Approximately 94.6% of our Pressure Pumping business
segment revenue was derived from hydraulic fracturing services for the three months ended March 31, 2018, compared to 93.2% for the three months ended March 31, 2017.
Pressure Control
revenue increased by $9.5 million, or 51.4%, to $28.0 million for the three months ended
March 31, 2018, from $18.5 million for the three months ended March 31, 2017. This increase was primarily attributable to a 22.4% increase in weighted average utilization to 31.4% and a 55.1% increase in weighted average revenue per
day to $20,246 for the three months ended March 31, 2018. The number of
27
days for which we generated revenue (revenue days) for the three months ended March 31, 2018 totaled 2,638 compared to 2,418 for the three months ended March 31, 2017. The
change in utilization and pricing accounted for 18.2% and 81.8% of the Pressure Control revenue change, respectively.
Wireline
revenue increased by $13.0 million, or 139.8%, to $22.3 million for the three months ended
March 31, 2018, from $9.3 million for the three months ended March 31, 2017. The increase was primarily attributable to a 52.3% increase in utilization to 39.1% and a 77.5% increase in revenue per day to $13,105 for the three months
ended March 31, 2018. Approximately 82.8% of our Wireline business segment revenue was derived from unconventional services for the three months ended March 31, 2018, compared to 68.3% for the three months ended March 31, 2017. The
change in utilization and pricing accounted for 24.9% and 75.1% of the Wireline revenue change, respectively.
Direct operating
expenses
.
The following table provides our direct operating expenses by business segment for the periods indicated (
in thousands of dollars
):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2018
|
|
|
2017
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
Directional Drilling
|
|
$
|
30,849
|
|
|
$
|
23,584
|
|
Pressure Pumping
|
|
|
40,015
|
|
|
|
21,162
|
|
Pressure Control
|
|
|
20,590
|
|
|
|
15,351
|
|
Wireline
|
|
|
15,038
|
|
|
|
6,739
|
|
|
|
|
|
|
|
|
|
|
Total direct operating expenses
|
|
$
|
106,492
|
|
|
$
|
66,836
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses for the three months ended March 31, 2018 increased by $39.7 million, or
59.4%, to $106.5 million, from $66.8 million for the three months ended March 31, 2017. The increase in direct operating expense was attributable to our business segments as follows:
Directional Drilling
direct operating expenses increased by $7.2 million, or 30.5%, to
$30.8 million for the three months ended March 31, 2018, from $23.6 million for the three months ended March 31, 2017. This increase was primarily attributable to a 14.7% increase in rig days to 3,706 over the same period, which
in turn resulted in increased revenue days driving higher operating expenses associated with both personnel and equipment.
Pressure Pumping
direct operating expenses increased by $18.8 million, or 88.7%, to
$40.0 million for the three months ended March 31, 2018, from $21.2 million for the three months ended March 31, 2017. This increase was primarily attributable to increased activity driven by a 62.8% increase in hydraulic
fracturing stages completed, which resulted in an increase in materials, equipment and personnel costs.
Pressure Control
direct operating expenses increased by $5.2 million or 33.8%, to
$20.6 million for the three months ended March 31, 2018, from $15.4 million for the three months ended March 31, 2017. This increase was primarily attributable to increased market activity, including a 22.4% increase in weighted
average utilization and a 9.1% increase in revenue days, which resulted in increased costs associated with personnel, equipment and materials.
Wireline
direct operating expenses increased by $8.3 million, or 123.9%, to $15.0 million for
the three months ended March 31, 2018, from $6.7 million for the three months ended March 31, 2017. This increase was primarily attributable to increased market activity, including a 52.3% increase in utilization and a 16% increase in
head count, which resulted in increased costs associated with personnel, equipment and consumables.
28
General and administrative expenses
. SG&A expenses represent the costs
associated with managing and supporting our operations. These expenses increased by $12.2 million, or 68.9%, to $29.9 million for the three months ended March 31, 2018, from $17.7 million for the three months ended March 31,
2017. The increase in general and administrative expenses was primarily driven by stock based compensation expense of $9.9 million which was recognized as a result our IPO. In addition, audit fees relating to 2017 and outsourced services
including internal controls and tax consultancy and compliance also contributed to the increase in the first quarter of 2018.
Depreciation and amortization
. Depreciation and amortization decreased by $0.5 million, or 4.3%, to $11.1 million for
the three months ended March 31, 2018, from $11.6 million for the three months ended March 31, 2017. The decrease in depreciation and amortization is primarily attributed to the fully amortized trademarks and fully depreciated tools
that are still in use.
Gain on disposition of assets, net
. Net gain on disposition of assets for three months ended
March 31, 2018 was $0.1 million, primarily attributable to Wirelines gain on equipment disposals, offset by losses in other segments, compared to a $1.7 million gain on disposition of assets, primarily attributable to the
disposition of pressure pumping and wireline assets for the three months ended March 31, 2017.
Interest expense
. Net
interest expense increased by $7.6 million, or approximately 292.3%, to $10.2 million for the three months ended March 31, 2018, compared to $2.6 million for the three months ended March 31, 2017. The increase in interest
expense was primarily due to $5.3 million of unamortized term loan discount expense, accelerated deferred financing costs of $3.0 million, and a prepayment fee of $1.3 million as a result of extinguishing the Former Revolving Credit
Facility (defined below) and Former Term Loan (defined below) during the first quarter of 2018. The increase was offset by $1.0 million reduction in interest expense due to having less debt outstanding in the three months ended March 31,
2018.
Adjusted EBITDA
. Adjusted EBITDA for three months ended March 31, 2018 increased by $11.5 million to
$15.5 million from $4.0 million for the three months ended March 31, 2017. The change in Adjusted EBITDA by business segment was as follows:
Directional Drilling
Adjusted EBITDA decreased by $1.1 million, or 29.7%, to $2.6 million in
the three months ended March 31, 2018, compared to $3.7 million in the three months ended March 31, 2017. The decrease was primarily attributable to a 30.5% increase in direct operating costs and a 17.7% increase in SG&A expenses
due to increased activity levels and elevated motor rental expense primarily due to third-party maintenance turnaround time.
Pressure Pumping
Adjusted EBITDA increased by $6.2 million, or 167.6% to $9.9 million in the
three months ended March 31, 2018, compared to $3.7 million in the three months ended March 31, 2017. The increase was primarily attributable to a 101.5% increase in revenue driven by increased frac activity, which was partially
offset by a 88.7% increase in direct operating expenses and a 52.3% increase in SG&A expenses incurred as the business deployed additional equipment and increased activity levels.
Pressure Control
Adjusted EBITDA increased by $3.9 million to $3.6 million in the three months
ended March 31, 2018, compared to $(0.3) million in the three months ended March 31, 2017. The increase was primarily attributable to a 51.4% increase in revenue driven by increased completions and workover activity, which was offset by a
33.8% increase in direct operating expenses and a 31.8% increase in SG&A expense driven by increased personnel, materials and overhead costs.
Wireline
Adjusted EBITDA increased by $4.0 million, to $2.6 million in the three months ended
March 31, 2018, compared to $(1.4) million in the three months ended March 31, 2017. The increase was primarily attributable to a 139.8% increase in revenue driven by increased pricing and utilization, partially offset by a 123.9% increase
in direct operating expenses and a 17.5% increase in SG&A expense driven by increased personnel, consumables and overhead costs resulting from increased utilization.
29
Liquidity and Capital Resources
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 to date have been capital contributions from our equity holders and borrowings under our former revolving credit facility (the Former Revolving Credit Facility),
our former $40.0 million term loan (the Former Term Loan), the New ABL Facility (as defined below) and cash flows from operations. At March 31, 2018, we had $16.6 million of cash and equivalents and $61.4 million
available to draw on the New ABL Facility, which resulted in a total liquidity position of $78.0 million.
As our drilling and
completion activity in the United States has increased with the rise in commodity prices since 2016, our cash flow from operations has begun to improve and we expect cash flow to continue to improve if drilling and completion activity continues to
increase. However, there is no certainty that cash flow will continue to improve or that we will have positive operating cash flow for a sustained period of time. Our operating cash flow is sensitive to many variables, the most significant of which
are utilization and profitability, the timing of billing and customer collections, payments to our vendors, repair and maintenance costs and personnel, any of which may affect our cash available.
Our primary use of capital has been for investing in property and equipment used to provide our services. Our primary uses of cash is for
replacement and growth capital expenditures, including acquisitions and investments in property and equipment. We regularly monitor potential capital sources, including equity and debt financings, in an effort to meet our planned capital
expenditures and liquidity requirements. Our future success will be highly dependent on our ability to access outside sources of capital.
The
following table sets forth our cash flows for the periods indicated (in thousands of dollars) presented below:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2018
|
|
|
2017
|
|
Net cash provided by (used in) operating activities
|
|
$
|
10,401
|
|
|
$
|
(19,475
|
)
|
Net cash provided by (used in) investing activities
|
|
|
(11,416
|
)
|
|
|
24,216
|
|
Net cash provided by (used in) financing activities
|
|
|
8,910
|
|
|
|
(6,004
|
)
|
|
|
|
|
|
|
|
|
|
Net change in cash
|
|
|
7,895
|
|
|
|
(1,263
|
)
|
|
|
|
|
|
|
|
|
|
Cash balance end of period
|
|
$
|
16,646
|
|
|
$
|
10,956
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
Net cash provided by operating activities was $10.4 million for the three months ended March 31, 2018, compared to net cash used in
operations of $19.5 million for three months ended March 31, 2017. The 2018 increase in operating cash flows was primarily attributable to faster collection of trade receivables and improved performance compared to lower utilization and
pricing as a result of prevailing market conditions in 2017.
Our operating cash flow is sensitive to many variables, the most significant
of which are utilization and profitability, the timing of billing and customer collections, payments to our vendors, repair and maintenance costs and personnel, any of which may affect our cash available.
Net cash provided by (used in) investing activities
Net cash used in investing activities was $11.4 million for three months ended March 31, 2018, compared to net cash provided by
investing activities of $24.2 million for the three months ended March 31, 2017. The cash flow used in investing activities for the three months ended March 31, 2018 was primarily used on our existing fleet capital spending and to
activate our fourth frac spread compared to the cash provided by acquisition activities in 2017.
30
We used $12.4 million to purchase equipment and we received $1.0 million in exchange
for selling assets for the three months ended March 31, 2018, as compared to the three months ended March 31, 2017, when we used $4.2 million of cash to purchase equipment and received $28.4 million in exchange for selling
assets.
Net cash provided by (used in) financing activities
Net cash provided by financing activities was $8.9 million for three months ended March 31, 2018, compared to net cash used in
financing activities of $6.0 million for the three months ended March 31, 2017. Net cash provided by financing activities was primarily the result of net proceeds received from the closing of our IPO totaling $90.5 million, which was
offset by the repayments under our Former Revolving Credit Facility and Former Term Loan, which totaled $92.3 million. In connection with the settlement of the Former Term Loan, a prepayment fee of 3%, or approximately $1.3 million was
paid. Additionally, $1.3 million was paid for treasury shares in connection with the settlement of equity based compensation, net of taxes, which vested during the three months end March 31, 2018.
Our Credit Facilities
Former Revolving Credit
Facility
The Company had a revolving credit facility (the Former Revolving Credit Facility), which had a maximum borrowing
facility of $110.0 million that was scheduled to mature on September 19, 2018. All obligations under the credit agreement for the Former Revolving Credit Facility were collateralized by substantially all of the assets of the Company. The
Former Revolving Credit Facilitys credit agreement contained customary restrictive covenants that required the Company not to exceed or fall below two key ratios, a maximum loan to value ratio of 70% and a minimum liquidity of
$7.5 million. In connection with the closing of the IPO on February 13, 2018, we fully repaid and terminated the Former Revolving Credit Facility. No early termination fees were incurred by the Company in connection with the termination of
the Former Revolving Credit Facility. A loss on extinguishment of $0.3 million relating to unamortized deferred costs was recognized in interest expense.
Former Term Loan
The Company also had a
four-year, $40.0 million term loan agreement with a lending group, which included Archer Well Company Inc. (Archer) and an affiliate of Quintana Capital Group, L.P. (Quintana) that was scheduled to mature on
December 19, 2020. The Former Term Loan agreement contained customary restrictive covenants that required the Company not to exceed or fall below two key ratios, a maximum loan to value ratio of 77% and a minimum liquidity of
$6.75 million. The interest rate on the unpaid principal was 10.0% interest per annum and accrued on a daily basis. At the end of each quarter all accrued and unpaid interest was paid in kind by capitalizing and adding to the outstanding
principal balance. In connection with the closing of the IPO on February 13, 2018, the Former Term Loan was settled in full by cash and common shares in the Company. In connection with the settlement of the Former Term Loan, a prepayment fee of
3%, or approximately $1.3 million was paid. The prepayment fee is recorded as a loss on extinguishment and included within interest expense. The Company also recognized $5.4 million of unamortized discount expense and $1.7 million of
unamortized deferred financing cost.
New ABL Facility
In connection with the closing of the IPO on February 13, 2018, we entered into a new semi-secured asset-based revolving credit agreement
(the New ABL Facility) with each lender party thereto and Bank of America, N.A. as administrative agent and collateral agent. The New ABL Facility replaced the Former Revolving Credit Facility, which was terminated in conjunction with
the effectiveness of the New ABL Facility. The New ABL Facility provides for a $100.0 million revolving credit facility subject to a borrowing base. Upon closing of the New ABL the borrowing capacity was $77.6 million and
$13.0 million was immediately drawn. The loan interest rate on the borrowings outstanding at March 31, 2018, was 4.63%. As of March 31, 2018, $13.0 million was outstanding under the New ABL Facility.
31
The New ABL Facility contains various affirmative and negative covenants, including financial
reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions) and transactions with affiliates.
Certain affirmative covenants, including certain reporting requirements and requirements to establish cash dominion accounts with the administrative agent, are triggered by failing to maintain availability under the New ABL Facility at or above
specified thresholds or by the existence of an event of default under the New ABL Facility. The New ABL Facility provides for some exemptions to its negative covenants allowing the Company to make certain restricted payments and investments; subject
to maintaining availability under the New ABL Facility at or above a specified threshold and the absence of a default.
The New ABL
Facility contains a minimum fixed charge coverage ratio of 1.0 to 1.0 that is triggered when availability under the New ABL Facility falls below a specified threshold and is tested until availability exceeds a separate specified threshold for 30
consecutive days.
The New ABL Facility contains events of default customary for facilities of this nature, including, but not limited,
to: (i) events of default resulting from the Borrowers failure or the failure of any credit party to comply with covenants (including the above-referenced financial covenant during periods in which the financial covenant is tested); (ii)
the occurrence of a change of control; (iii) the institution of insolvency or similar proceedings against the Borrowers or any credit party; and (iv) the occurrence of a default under any other material indebtedness the Borrowers 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 New ABL Facility, the lenders will be able to declare any outstanding principal balance of our New ABL Facility,
together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies, including remedies against the collateral, as more particularly specified in the New ABL Facility. As of March 31, 2018 the Company was in
compliance with debt covenants.
Capital Requirements and Sources of Liquidity
During the three months ended March 31, 2018, our capital expenditures, excluding acquisitions, were approximately $2.7 million,
$5.2 million, $4.4 million and $0.1 million in Directional Drilling, Pressure Pumping, Pressure Control and Wireline business segments, respectively, for aggregate net capital expenditures of approximately $10.7 million,
primarily for the activation of our third and fourth frac spreads and capital expenditures on existing equipment.
For the three months
ended March 31, 2017, our capital expenditures, excluding acquisitions, were approximately $2.1 million, $1.2 million, $0.9 million and a nominal amount in our Directional Drilling, Pressure Pumping, Pressure Control and Wireline
business segments for aggregate net capital expenditures of approximately $4.2 million, primarily for purchase of new drilling motors and replacement of MWD kits.
As previously disclosed in our 2017 Annual Report on Form
10-K
for the fiscal year ended
December 31, 2017, we currently estimate that our capital expenditures for our existing fleets and approved capacity additions during the remainder of 2018 will range from $75.0 million to $85.0 million, including approximately
$20.0 million to $22.0 million for the remaining cost to purchase equipment for our fourth pressure pumping fleet, approximately $14.0 million to $17.0 million to invest in large diameter coiled tubing units, and the remainder
for maintenance and other capital expenditures. We expect to fund these expenditures through a combination of cash on hand, cash generated by our operations and borrowings under our New ABL Facility.
We believe that the proceeds from the IPO, our operating cash flow and available borrowings under our New ABL Facility will be sufficient to
fund our operations for the next twelve months. As drilling and completion activity in the United States has increased with the rise in commodity prices since 2016, our cash flow from operations has begun to improve and we expect cash flow to
continue to improve if drilling and completion activity continues to increase. However, our operating cash flow is sensitive to many variables, the most significant of which are utilization and profitability, the timing of billing and customer
collections, payments to our vendors, repair and maintenance costs and personnel, any of which may affect our cash available. Significant additional capital expenditures will be required to conduct our operations and there can be no assurance that
operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures and make expected distributions. Further, we do not have a specific capital expenditures acquisition budget
for 2018
32
since the timing and size of acquisitions cannot be accurately forecasted. In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have
available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures or distributions and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through
borrowings under our New ABL Facility, joint venture partnerships, asset sales, offerings of debt and equity securities or other means. We cannot assure that this additional capital will be available on acceptable terms or at all. If we are unable
to obtain funds we need, we may not be able to complete acquisitions that may be favorable to us or to finance the capital expenditures necessary to conduct our operations.
Off-Balance
Sheet Arrangements
We had no
off-balance
sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation
S-K,
as of March 31, 2018.
Critical Accounting Policies
Other than the accounting impacts resulting from our adoption of ASC 606, which are discussed in Notes 2 and 14 to our condensed consolidated
financial statements herein, as of March 31, 2018, there were no significant changes in our critical accounting policies previously disclosed in Part II, Item 7 of our Annual Report on Form
10-K
for the
fiscal year ended December 31, 2017, filed with the SEC on March 30, 2018.
Recent Accounting Pronouncements
See Note 2 to our condensed consolidated financial statements for a discussion of recently issued accounting pronouncements.