Johnson Rice Energy Conference
September 26-27, 2017
www.icdrilling.com
Preliminary Matters
Various statements contained in this presentation, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. These forward-
looking statements may include projections and estimates concerning the timing and success of specific projects and our future revenues, income and capital spending. Our forward-looking statements are generally
accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal,” “will” or other words that convey the uncertainty of future events or outcomes. The
forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update these statements unless required by law, and we caution you not to rely on them
unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable,
they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control.
These and other important factors, including those discussed under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Company’s filings
with the Securities and Exchange Commission, including the Company’s Annual Report on Form 10-K, may cause our actual results, performance or achievements to differ materially from any future results,
performance or achievements expressed or implied by these forward-looking statements. These risks, contingencies and uncertainties include, but are not limited to, the following:
• our inability to implement our business and growth strategy;
• a sustained decrease in domestic spending by the oil and natural gas exploration and production industry;
• decline in or substantial volatility of crude oil and natural gas commodity prices;
• fluctuation of our operating results and volatility of our industry;
• inability to maintain or increase pricing on our contract drilling services;
• delays in construction or deliveries of reactivated, upgraded, converted or new-build land drilling rigs;
• the loss of material customers, financial distress or management changes of potential customers or failure to obtain contract renewals and additional customer contracts for our drilling services;
• an increase in interest rates and deterioration in the credit markets;
• our inability to raise sufficient funds through debt financing and equity issuances needed to fund future rig construction projects;
• additional leverage associated with borrowings to fund rig conversions and additional newbuild rigs;
• our inability to comply with the financial and other covenants in debt agreements that we may enter into as a result of reduced revenues and financial performance;
• a substantial reduction in borrowing base under our revolving credit facility as a result of a decline in the appraised value of our drilling rigs or substantial reduction in our rig utilization;
• overcapacity and competition in our industry; unanticipated costs, delays and other difficulties in executing our long-term growth strategy;
• the loss of key management personnel;
• new technology that may cause our drilling methods or equipment to become less competitive;
• labor costs or shortages of skilled workers;
• the loss of or interruption in operations of one or more key vendors;
• the effect of operating hazards and severe weather on our rigs, facilities, business, operations and financial results, and limitations on our insurance coverage;
• increased regulation of drilling in unconventional formations;
• the incurrence of significant costs and liabilities in the future resulting from our failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;
• the potential failure by us to establish and maintain effective internal control over financial reporting;
• lack of operating history as a contract drilling company; and
• uncertainties associated with any registration statement, including financial statements, we may be required to file with the SEC.
All forward-looking statements are necessarily only estimates of future results, and there can be no assurance that actual results will not differ materially from expectations, and, therefore, you are cautioned not to place
undue reliance on such statements. Any forward-looking statements are qualified in their entirety by reference to the factors discussed throughout this presentation and in the Company’s filings with the Securities and
Exchange Commission, including the Company’s Annual Report on Form 10-K. Further, any forward-looking statement speaks only as of the date of this presentation, and we undertake no obligation to update any
forward-looking statement to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of unanticipated events.
Adjusted Net Loss, EBITDA and adjusted EBITDA are supplemental non-GAAP financial measures that are used by management and external users of the Company’s financial statements, such as industry analysts,
investors, lenders and rating agencies. The Company’s management believes adjusted Net Loss, EBITDA and adjusted EBITDA are useful because such measures allow the Company and its stockholders to more
effectively evaluate its operating performance and compare the results of its operations from period to period and against its peers without regard to its financing methods or capital structure. See non-GAAP financial
measures at the end of this presentation for a full reconciliation of Net Loss to adjusted Net Loss, EBITDA and adjusted EBITDA.
2
ICD Rig Location
1. Based upon date of initial drilling operations for newbuild 200 Series rig or converted 100 series rig.
2. Market data as of 9/22/17. Credit facility, debt, shares outstanding and cash balances as of 6/30/17. Debt balance excludes $0.5 million of long-term vehicle capital lease obligations.
3. Total credit facility commitment less outstanding borrowings @ 6/30/17.
Corporate Snapshot
Sectors only pure play, pad-optimal growth story
• Fleet composed of fourteen 200 Series ShaleDriller® rigs:
‒ 100% of fleet contracted and operating
‒ Two additional 200 Series newbuilds expected to be delivered with
incremental investment of ~ 50% of historical cost of equivalent
newbuild 200 Series rigs
• The speed, efficiency and safety offered by ICD’s rigs dramatically reduce
drilling times, thereby saving significant capex dollars for E&P operators
Established reputation for operational excellence and safety
• Safety focused operations (SEMS II compliant)
• Average 200 Series ShaleDriller® fleet age: ~2.9 years(1)
• Best-in-class operating stats
• Industry leading utilization
• Established, experienced and well-known management team
• Work with well-known customers who pay for quality
Current Operational Footprint
Current Capitalization & Liquidity (2)
US$MM, unless otherwise noted
Share Price ($/Share) 3.72
Share Outstanding (MM) 37.8
Equity Value 140.6
Long-term debt – Credit Facility 39.0
Cash 5.5
Aggregate Value 185.1
Credit Facility Unused Capacity(3) 46.0
Cash 5.5
Total Current Liquidity 51.5
Book Value of Equity 246.4
Total Capitalization 285.4
3
Texas
Oklahoma
Arkansas
Louisiana
New Mexico
Target Areas of Growth
Texas, Louisiana, Oklahoma
and New Mexico
September 22, 2017
• Contract Extensions:
- Recent contract extension on four rigs with scheduled contract expirations during the
remainder of 2017 at operating rates in the high-teens adds three rig years of additional
backlog resulting in the following updated backlog information:
• Harvey impacts and updated 3Q’17 guidance (as of 9/27/17):
- No material damage or impacts to rig equipment. Some weather related repairs and temporary
relocation costs during the quarter
- Expected revenue days of approximately 1,235 days (low end of prior guidance)
- Expected adjusted net loss between $0.14 and $0.15 per share
Operational & Financial Update
4
Q4’17 Q1’18 Q2’18 Q3’18 Q4’18 2019
Rigs in
Backlog
14 13.2 8.0 3.4 1.4 0.6
Current or past ICD customers
High-Quality Customer Base
ICD Customers Include Some of the Highest Quality,
Most Active Players in ICD Target MarketsICD has established a deep and high-quality
customer base composed of some of the most
active players in ICD target markets
• All rigs operating on term contracts
• ICD’s fleet standardization provides several benefits for customers
including consistent branding, predictability in performance and quick
understanding of the rig’s capabilities
• ICD is focused on strategically expanding its customer base
– Target markets are Texas and the contiguous states
– Target customers with significant investments and willingness to drill
through industry cycles
– Target operators who value safety and efficient operations
– Focus on customers willing to enter into long-term contractual
relationships
– Diverse between oil, gas and oil/gas in the most active basins
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ICD Customer Base Breakdown(1)
Source: Wall Street Consensus Estimates and Company Guidance
64%
36%
Public Private
(1) Percentage of rigs contracted with publicly-traded and private customers as of July 14, 2017.
Company 2017E Total Capex ($MM)
Pioneer Natural Resources (PXD) 4,800
Concho Resources (CXO) 4,600
Devon Energy Corporation (DVN) 2,300
Apache Corporation (APA) 2,000
Anadarko Petroleum Corporation (APC) 1,380
Occidental (OXY) 1,200
Cimarex Energy (XEC) 1,200
Parsley Energy (PE) 1,150
Energen Resources (EGN) 1,040
Newfield Exploration (NFX) 1,000
Diamondback Energy (FANG) 800
Encana (ECA) 925
SM Energy (SM) 700
RSP P rmian-SHEP (RSPP) 625
Laredo Petroleum (LPI) 530
Callon Petroleum (CPE) 500
WPX 415
GeoSouthern (GEP Haynesville) NA
BHP Billiton (BHP) 400
Financial Flexibility
ICD backlog expanding, with contract tenors and
dayrates increasing for all contracts signed since
12/31/16
As of 6/30/17: ICD remaining capital budget for
2017 was $4.4 million and includes costs to
complete final rig conversion, which began
operations end of July ‘17
ICD has already made significant investment
towards next two newbuild ShaleDriller® rigs -
following completion of these projects, ICD fleet
would be comprised of sixteen 200 Series
ShaleDriller® rigs
ICD is ideally positioned to complete these next
two newbuild capital projects when market
conditions dictate while still maintaining a strong
liquidity position
ICD in preferential tax position
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Financial Flexibility and Liquidity
$MM
Cash @ 6/30/17 $5.5
Plus: Revolving Credit Facility Capacity @ 6/30/17 85.0
Less: Outstanding Borrowings @ 6/30/17 (39.0)
Total Liquidity $51.5
Less: Remaining 2017 capex budget(1) (4.4)
2017 planned asset sales(1) 6.4
Potential incremental growth capex(1) (22.0)
Total Liquidity Adjusted(2) $ 31.5
(1) As of 6/30/17. Planned assets sales = estimated fair value, less selling costs, of assets held for sale as of 6/30/17. Growth capex = estimated incremental investment for final two newbuild rigs,. Actual costs may differ based upon final
rig configuration and contractual requirements.
(2) Assumes all budgeted capex, planned asset sales and potential growth capex occurred 6/30/17, and funded through additional borrowings under existing credit facility. Excludes debt associated with vehicle capital leases.
Land Drilling Overview
7
As E&P operators continue shifting towards a wellbore manufacturing
model, they focus on the safest operations and rigs that consistently
eliminate non-productive time and drive operating efficiencies
• Pad-optimal rigs represent equipment that is best suited for wellbore manufacturing
• Drill more wells per year and accelerate E&P operators’ production profiles and cash flows
• Eliminate substantial spread costs
As lateral length and pad size and complexity continue to expand, the value
proposition of pad-optimal rig technology increases significantly
Market access to pad-optimal rigs is extremely limited, with ICD and
competitor pad-optimal fleets at full effective utilization
• AC is no longer a differentiating technology
• Bolt-on/after-thought upgrades not fit-for-purpose, and do not deliver value proposition of true pad-
optimal rigs
ShaleDriller® rigs eliminate non-productive time,
drill longer laterals faster and for less cost, and
materially reduce spread costs/cycle times
✓ICD does not work at the margin: pad-optimal equipment
essential for development of core E&P acreage in lower
commodity price environment
✓Systems flexibility to partner with E&P and other service
companies to achieve full systems optimization from
technology/data integration
✓Standardized fleet supports lower capital intensity
✓By driving faster cycle times and drilling efficiencies, ICD’s rigs
materially bend the E&P cost curve down – justifying a larger
piece of the AFE “pie”
Key Differentiators Driving ICD’s
Compelling Value Proposition
8
High Pressure Mud Pumps
Pad-Optimal Rig Characteristics -
As Defined by E&P Operators
Omni-Directional Walking System
• Allows rig to move in any direction quickly between wellheads, rapidly and efficiently adjusts to
misaligned wellbores, walks over raised well heads and increases safety
• Superior to skidding systems which can only move to properly aligned wells in a straight line
• Self-leveling capabilities
1,500 hp Drawworks
• Rigs powered with 1,500 hp drawworks are well suited to the majority of unconventional resource
formations
• Ideally sized for drilling longer laterals while occupying a small footprint on the job site
Bi-Fuel Capabilities
• Operator can change between diesel or natural gas mix
• Use of natural gas/diesel blend can result in major savings
• Reduces carbon emissions
• 7,500 psi mud pumps allow for drilling mud to be pumped through extended horizontal laterals
• Necessary for drilling the long laterals required by complex horizontal drilling programs
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Fast Moving
• Specifically designed to reduce cycle times (reduces rig-move time between drilling locations)
• Designed to minimize truck loads (and times) required for moves between drilling sites; complete move
in 48 hours (4 daylight days or less)
AC Programmable
• Uses a variable frequency drive that allows for precise computer control of key drilling parameters
during operations, providing accurate drilling through the wellbore
• AC rigs drill faster with less open hole time and superior wellbore geometry vs. mechanical or SCR rigs
• In today’s market, it is no longer a differentiating feature, it is a requirement
✓$50 oil long term
✓Peak rig count – but high grading within
✓Evolutionary changes in equipment specifications
✓Full data integration / systems optimization
✓End of the dayrate model – shift towards risk-
sharing, performance-based economics
What does the future hold?
10
Balance Sheet – June 30, 2017
12
June 30, 2017 December 31, 2016
Assets
Cash and cash equivalents 5,465$ 7,071$
Accounts receivable, net 12,946 11,468
Inventories 2,407 2,336
Assets held for sale 6,388 3,915
Prepaid expenses and other current assets 3,737 3,102
Total current assets 30,943 27,892
Property, plant and equipment, net 271,725 273,188
Other long-term assets, net 865 1,027
Total assets 303,533$ 302,107$
Liabilities and Stockholders’ Equity
Liabilities
Current portion of long-term debt (1) 468$ 441$
Accounts payable 10,825 10,031
Accrued liabilities 5,867 7,821
Total current liabilities 17,160 18,293
Long-term debt (2) 39,527 26,078
Deferred income taxes 476 396
Other long-term liabilities 1 88
Total liabilities 57,164 44,855
Commitments and contingencies
Stockholders’ equity
Common stock, $0.01 par value, 100,000,000 shares authorized;
38,025,637 and 37,831,723 shares issued, respectively;
and 37,807,467 and 37,617,920 shares outstanding, respectively 378 376
Additional paid-in capital 325,630 323,918
Accumulated deficit (77,920) (65,347)
Treasury stock, at cost, 218,170 and 213,803 shares, respectively (1,719) (1,695)
Total stockholders’ equity 246,369 257,252
Total liabilities and stockholders’ equity 303,533$ 302,107$
Income Statement – Q2’17
13
March 31,
2017 2016 2017 2017 2016
Revenues 21,285$ 15,155$ 20,236$ 41,521$ 37,610$
Costs and expenses
Operating costs 15,808 7,398 14,898 30,706 19,965
Selling, general and administrative 3,435 5,005 3,718 7,153 8,626
Depreciation and amortization 6,335 5,816 6,256 12,591 11,641
Asset impairment, net 546 - 129 675 -
Loss (gain) on disposition of assets, net 745 37 828 1,573 (88)
Total cost and expenses 26,869 18,256 25,829 52,698 40,144
Operating loss (5,584) (3,101) (5,593) (11,177) (2,534)
Interest expense (686) (1,059) (630) (1,316) (2,036)
Loss before income taxes (6,270) (4,160) (6,223) (12,493) (4,570)
Income tax expense 34 31 46 80 35
Net loss (6,304)$ (4,191)$ (6,269)$ (12,573)$ (4,605)$
Loss per share:
Basic and Diluted (0.17)$ (0.12)$ (0.17)$ (0.33)$ (0.16)$
Weighted average number of common shares outstanding:
Basic and Diluted 37,679 33,608 37,546 37,613 28,812
Six Months EndedThree Months Ended
June 30, June 30,
Non-GAAP Financial Measures
14
Adjusted net loss, EBITDA and adjusted EBITDA are supplemental non-GAAP financial measure that are used by
management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
In addition, adjusted EBITDA is consistent with how EBITDA is calculated under our revolving credit facility for purposes of
determining our compliance with various financial covenants. We define “EBITDA” as earnings (or loss) before interest, taxes,
depreciation, and amortization, and we define “adjusted EBITDA” as EBITDA before stock-based compensation, non-cash
asset impairments, gains or losses on disposition of assets, and other non-recurring items added back to, or subtracted from,
net income for purposes of calculating EBITDA under our revolving credit facility. Neither adjusted net loss, EBITDA or
adjusted EBITDA is a measure of net income as determined by U.S. generally accepted accounting principles (“GAAP”).
Management believes adjusted net loss, EBITDA and adjusted EBITDA are useful because they allow our stockholders to
more effectively evaluate our operating performance and compliance with various financial covenants under our revolving
credit facility and compare the results of our operations from period to period and against our peers without regard to our
financing methods or capital structure or non-recurring, non-cash transactions. We exclude the items listed above from net
income (loss) in calculating adjusted net loss, EBITDA and 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. None of adjusted net loss, EBITDA or adjusted EBITDA should
be considered an alternative to, or more meaningful than, net income (loss), the most closely comparable financial measure
calculated in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from
adjusted net loss, EBITDA and adjusted EBITDA are significant components in understanding and assessing a company’s
financial performance, such as a company’s return of assets, cost of capital and tax structure. Our presentation of adjusted
net loss, EBITDA and adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual
or non-recurring items. Our computations of adjusted net loss, EBITDA and adjusted EBITDA may not be comparable to
other similarly titled measures of other companies.
The table on the following page present a reconciliation of net loss to adjusted net loss, EBITDA and adjusted EBITDA.
Non-GAAP Financial Measures
15
Reconciliation of Net Loss to Adjusted Net Loss:
Reconciliation of Net Loss to EBITDA and Adjusted EBITDA:
See footnote explanations on following page.
June 30, 2017 June 30, 2016 March 31, 2017 June 30, 2017 June 30, 2016
(in thous nds)
Net loss $ (6,304) $ (4,191) $ (6,269) $ (12,573) $ (4,605)
Add back:
Income tax expense 34 31 46 80 35
Interest expense 686 1,059 630 1,316 2,036
Depreciation and amortization 6,335 5,816 6,256 12,591 11,641
EBITDA 751 2,715 663 1,414 9,107
St ck-based compensation 1,157 1,205 1,012 2,169 2,360
Stock-based compensation - executive retirement (4) - (67) - - (67)
Asset impairment, net (1) 546 - 129 675 -
Loss (gain) on disposition of assets, net (2) 745 37 828 1,573 (88)
Executive retirement (4) - 1,552 - - 1,552
Adjusted EBITDA $ 3,199 $ 5,442 $ 2,632 $ 5,831 $ 12,864
(Unaudited)
Six Months EndedThree Months Ended
(Unaudited)
Amount
Per
Share
Amount
Per
Share
Amount
Per
Share
Amount
Per
Share
Amount
Per
Share
(i thousands)
et loss $ (6,304) $ (0.17) $ (4,191) $ (0.12) $ (6,269) $ (0.17) $(12,573) $ (0.33) $ (4,605) $(0.16)
Asset impairment, net (1) 546 0.02 - - 129 0.01 675 0.02 - -
Loss (gain) on disposition of assets, net (2) 745 0.02 37 0.00 828 0.02 1,573 0.04 (88) (0.00)
Write-off of deferred financing costs (3) - - 504 0.01 - - - - 504 0.02
Ex cu ive retirement (4) - - 1, 52 0.05 - - - - 1,552 0.05
Stock-based compens - executive retirement (4) - - ( 7) (0.01) - - - - (67) (0.00)
Adjusted net loss $ (5,013) $ (0.13) $ (2, 65) $ (0.07) $ (5,312) $ (0.14) $(10,325) $ (0.27) $ (2,704) $(0.09)
Six Months Ended
(Unaudited)
Three Months Ended
(Unaudited)
June 30, 2017 June 30, 2016 March 31, 2017 June 30, 2017 June 30, 2016
Non-GAAP Financial Measures
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(1) In the second quarter of 2017, we recorded a $0.5 million, or $0.02 per share, non-cash impairment reflecting the estimated loss from the expected sale of our Galayda facility. In the first quarter of 2017, we
recorded a $0.1 million, or $0.01 per share, non-cash impairment representing the estimated damage to the mast of one of our rigs, net of insurance recoveries.
(2) In the second quarter of 2017, we recorded a loss on disposition of assets of $0.7 million, or $0.02 per share, primarily due a loss on the sale of drilling equipment previously designated as held for sale. In the
first quarter of 2017, we recorded a loss on disposition of assets of $0.8 million, or $0.02 per share, primarily due to non-cash disposal of equipment in connection with the upgrade to 7,500 psi mud systems.
(3) In the second quarter of 2016, we recorded $0.5 million, or $0.01 per share, related to the amortization of deferred financing costs in connection with a reduction of commitments under the Company’s revolving
credit facility.
(4) In the second quarter of 2016, we recorded $1.5 million, or $0.04 per share, of retirement benefits associated with the departure of an executive officer.
Non-GAAP Financial Measures
17
(1) Rig operating days represent the number of days our rigs are earning revenue under a contract during the period, including days that standby revenues are earned. For the three months ended June
30, 2017 and 2016 and March 31, 2017 there were zero, 368.4 and 77.9 operating days in which the Company earned revenue on a standby basis, respectively, including zero, 362.9 and 69.0
standby-without-crew days, respectively. For the six months ended June 30, 2017 and 2016 there were 77.9 and 554.1 operating days in which the Company earned revenue on a standby basis,
respectively, including 69.0 and 525.0 standby-without-crew days, respectively.
(2) Average number of operating rigs is calculated by dividing the total number of rig operating days in the period by the total number of calendar days in the period.
(3) Rig utilization is calculated as rig operating days divided by the total number of days our drilling rigs are available during the applicable period. During the third quarter of 2015, we elected to
remove our two 100 Series non-walking rigs from the marketed fleet pending completion of their planned rig conversions to 200 Series, pad-optimal status. The conversion of one of the 100 series
rig was completed during the second quarter of 2016 and the rig re-entered the marketed fleet in June 2016. The conversion of the second 100 series rig was completed in the second quarter of
2017 and the rig will begin operating in July 2017.
(4) Average revenue per operating day represents total contract drilling revenues earned during the period divided by rig operating days in the period. Excluded in calculating average revenue per
operating day are revenues associated with the reimbursement of out-of-pocket costs paid by customers of $1.1 million, $0.4 million and $1.0 million for the three months ended June 30, 2017 and
2016 and March 31, 2017, respectively, and $2.0 million and $1.6 million for the six months ended June 30, 2017 and 2016, respectively. Included in calculating average revenue per operating day
for the three and six months ended June 30, 2016 was $1.6 million and $1.8 million, respectively, of early termination revenues associated with a contract termination at the end of the first quarter
of 2016. The first and second quarter of 2017 did not include any early termination revenues.
(5) Average cost per operating day represents total direct operating costs incurred during the period divided by rig operating days in the period. The following costs are excluded in calculating average
cost per operating day: (i) out-of-pocket costs reimbursed by customers of $1.1 million, $0.4 million and $1.0 million for the three months ended June 30, 2017 and 2016 and March 31, 2017,
respectively and $2.0 million and $1.6 million for the six months ended June 30, 2017 and 2016, respectively, (ii) new crew training costs of $0.1 million for the three months ended June 30, 2017
and 2016 and March 31, 2017, and the six months ended June 30, 2017 and 2016, (iii) construction overhead costs expensed due to reduced rig construction activity of zero, $0.5 million and $0.2
million for the three months ended June 30, 2017 and 2016 and March 31, 2017, respectively, and $0.2 million and $1.0 million for the six months ended June 30, 2017 and 2016, respectively, (iv)
rig reactivation costs for the three months ended June 30, 2017 and March 31, 2017 of $0.3 million and $0.7 million, respectively, and $1.0 million for the six months ended June 30, 2017
(excluding $0.1 million of new crew training costs (included in (ii) above)), and (v) out-of-pocket expenses of $0.1 million, net of insurance recoveries, incurred as a result of damage to one of our
rig's mast during the first quarter of 2017.
June 30, 2017 June 30, 2016 March 31, 2017 June 30, 2017 June 30, 2016
Number of completed rigs end of period 14 14 14 14 14
Rig operating days (1) 1,111.2 732.2 1,072.9 2,184.1 1,675.3
Average number of operating rigs (2) 12.2 8.0 11.9 12.1 9.2
Rig utilization (3) 93.9% 65.6% 91.7% 92.8% 75.9%
Average revenue per operating day (4) $ 18,201 $ 20,116 $ 17,949 $ 18,077 $ 21,498
Average cost per operating day (5) $ 12,926 $ 8,757 $ 11,930 $ 12,435 $ 10,351
Average rig margin per operating day $ 5,275 $ 11,359 $ 6,019 $ 5,642 $ 11,147
Six Months EndedThree Months Ended
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