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| 8-K - 8-K - Independence Contract Drilling, Inc. | a8-kinvestorpresentation10.htm |
Investor Presentation
October 11, 2016
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 our new land drilling rigs;
• the loss of our customer, 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 our planned rig construction projects;
• 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;
• 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. Further, any forward-looking statement speaks only as of the date on which it is made, 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.
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 defines “EBITDA” as earnings (or loss) before interest, taxes, depreciation, and amortization, and it defines “Adjusted EBITDA” as EBITDA before stock-based compensation, and non-cash asset impairments and gain (or
loss) on asset disposition. EBITDA and Adjusted EBITDA are not measures of net income as determined by U.S. generally accepted accounting principles (“GAAP”).
The Company’s management believes 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. The Company excludes the items listed below from net income (loss) in calculating EBITDA and Adjusted EBITDA
because these amounts can vary substantially from company to company within the Company’s industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were
acquired. EBITDA and Adjusted EBITDA should not be considered alternatives to, or more meaningful than, net income (loss), the most closely comparable financial measure calculated in accordance with GAAP or as an indicator of the
Company’s operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax
structure, as well as stock-based compensation and the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. The Company’s presentation of EBITDA and Adjusted EBITDA should not be construed
as an inference that its results will be unaffected by unusual or non-recurring items. The Company’s computations of EBITDA and Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
2
ICD Rig Location(3)
1. A pad-optimal rig consists of four key drilling and two key moving attributes: 1,500 hp, bi-fuel capable, 7500psi high pressure mud systems, AC VFD drive, an omni-directional walking system and ability to undertake fast conventional rig moves safely.
2. Includes 200 Series ShaleDriller® rigs. Excludes 100 Series rigs. Final 100 Series rig scheduled for conversion when market conditions improve.
3. Idle rigs depicted as located in Galayda Yard/Houston, Texas.
4. Market data as of 10/7/16. Credit facility, debt and cash balances as of 6/30/16.
Corporate Snapshot
Sector’s most technologically advanced land drilling rigs
• Fleet composed of thirteen 200 Series ShaleDriller® rigs and one 100
Series ShaleDriller rig
‒ Remaining 100 Series rig scheduled for conversion to 200 Series
pad-optimal(1) status when market conditions improve
• 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: ~2.1 years
• Best-in-class operating stats: lateral length and uptime
• Industry leading utilization: ~76% during 1H’16(2)
• Established, experienced and well-known management team
• Work with well-known customers who pay for quality
Current Operational Footprint
Current Capitalization & Liquidity (4)
US$MM, unless otherwise noted
Share Price ($/Share) 5.45
Share Outstanding (MM) 37.6
Equity Value 204.9
Long-term debt – Credit Facility 16.4
Cash 7.1
Aggregate Value 228.4
Credit Facility Unused Capacity 68.3
Cash 7.1
Total Current Liquidity 75.4
Book Value of Equity 273.2
Total Capitalization 289.6
3
Texas
Oklahoma
Arkansas
Louisiana
New Mexico
Target Areas of Growth
Texas, Louisiana, Oklahoma
and New Mexico
October 11, 2016
Operational Update
• Since 2Q’16:
- Reactivated five rigs from idle/standby status
- Rig upgrades (two 7500psi upgrades, one 3rd mud pump upgrade)
• Entered 4Q’16 with 10 rigs earning revenue, including one rig on a
standby basis. Increase in inquiry levels across all of ICD target
markets for reactivation of idle rigs.
• Additional rig reactivations relative to expectations bring forward
reactivation/hiring costs into 3Q’16.
• Organizational update: consolidation of Galayda yard – field
operations without reducing rig build capabilities.
4
ICD is a leader in the rig replacement cycle – pad-optimal rigs are critical
in the progression of the U.S. unconventional drilling evolution
With industry leading fleet utilization, ICD is a rig provider of choice
By driving faster cycle times, ICD’s rigs bend the E&P cost curve down
ICD’s standardized fleet supports lower capital intensity
Modular construction gives ICD a low cost rig fleet and provides a
compounding capital advantage
ICD’s “Big Data” collection capability allows ICD to participate in the
next wave in drilling technology innovation
ICD’s rigs provide revenues and EBITDA with low maintenance capital
expenditures and tax burden
Key Differentiators Driving ICD’s
Compelling Value Proposition
5
9%
38%
29%
13%
11%
Competitor 4 Competitor 3 Competitor 2 Competitor 1 ICD (ShaleDriller®)
Dissecting the New Land Drilling Industry
6
20%
34%
33%
13%
New Land Drilling Industry – Pad-Optimal Fleet (2)
Land Drilling Industry – AC Rig Fleet (1)
1. Includes only 1,500 hp AC rigs
2. Includes ICD estimates for ICD and its four largest competitors. Excludes skidding rigs.
750 Rigs
Pad-optimal Skidding Non-Moving Other
New Land
Drilling
Industry
Source: ICD, Competitor Investor Presentations, Competitor Websites
As E&P operators continue the shift towards a wellbore
manufacturing model, the focus will be on the 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 accelerates E&P
operators’ production profiles and cash flows
Market access to pad-optimal rigs is extremely limited,
with only ~140 active today(2)
• AC is no longer a differentiating technology
- Of the ~750 1500hp AC rigs in the U.S., ICD estimates
only ~20% of them have the equipment necessary to be
pad-optimal
ICD’s pad-optimal rigs eliminate non-productive time,
drill longer laterals faster and for less cost, and
materially reduce cycle times
~140 Rigs
Source: Public Presentations
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
• High pressure 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
7
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
Value Proposition of ICD’s
ShaleDriller® Rig
• Mechanical and SCR rigs have shorter bit life, higher
wellbore deviation and longer open hole times – they drill
slower and with less precision than ICD’s ShaleDriller®
AC rigs
‒ Cycle time reductions gained using ICD’s
ShaleDriller® rigs bend the drilling cost curve
down
• Performance attributes like omni-directional walking, bi-
fuel capable, 1,500 hp drawworks, high pressure mud
systems, and fast moving capabilities are a rare
combination
‒ Only ~140 of these pad-optimal rigs are estimated
to be active in the North American fleet(1)
‒ ICD’s rig fleet has these capabilities, allowing for
operations on the largest pad drilling sites – even with
misaligned wellbores and uneven pads
As commodity prices rise, pad-optimal rigs will be in
short supply (and high demand) while legacy rigs will
continue to be a liability to drilling contractors without
pure-play, high-spec fleets
Pad Optimal ShaleDriller® vs. Non-Pad-Optimal
8
Pad Optimal ShaleDriller® vs. Legacy / SCR
• Legacy AC rigs move slower and cannot accommodate
complex pad drilling applications
• Pad-optimal rigs provide:
‒ Omni-directional walking – can move around complex
pads efficiently
‒ Ability to drill longer laterals
‒ Long, accurate gauge wells – completable
‒ Faster drilling times
‒ Self leveling, with no additional equipment required
‒ Able to adjust quickly to misaligned wellbores
‒ Minimizes formation damage
‒ Elimination of non-productive time and costs
‒ Fastest moving between wells and pads
Pad-optimal rigs provide the industry’s best value
proposition, even at higher dayrates
1. Includes ICD estimates for ICD and its four largest competitors. Excludes skidding rigs.
Optimizing High Density Pads
Eddy County New Mexico
Island Drilling Project
2013-2014
• Potential for 40 wells on single pad
• Record long laterals
• Walking up to 300ft between wells
• Bi-fuel drilling operation ($2,500/day
savings)
• Concrete coffin cellars for multi-wells
• SEMS II Compliant, Simultaneous
Operations
• Federal Land Regulations (BLM)
• Demand for standardized 7500 psi
equipment
0.0
1.0
2.0
3.0
4.0
5.0
6.0
0 10 20 30 40 50 60 70
$
M
M
Drilling Program Days Saved
Cutting only 39
days off a 295 day
drilling program
justifies the
incremental cost of
a $25k/day pad-
optimal rig
$16,000 Dayrate
$20,000 Dayrate $25,000 Dayrate
Incremental Cost of a Pad-Optimal Rig (2)
AFE Savings
Examples of ICD Delivering Significant Value
for E&P Operators
Cutting Cycle Times - Illustrative Savings vs Legacy Rigs
1. Assumes $75,000 operator spread cost over 70 days
2. Based on $12,000 dayrate for legacy rig for a 295 day program; incremental cost calculated as Pad-Optimal Rig Cost * (295 – Days Saved) – Legacy Rig Cost * 295 days
10
Case Study: Multi-Well Pad Drilling Program
The industry’s unconventional resource development
techniques are rapidly trending towards multi-well
development
• An operator drilling multi-well pads benefits from ICD’s pad-
optimal technology (vs. 1 – 2 wells per pad), by reducing cycle
times as the number of moves and move durations decline
‒ Non-pad-optimal rigs, with legacy skidding or slow walking
systems, are effective on 1-2 wells per pad but cannot
efficiently prosecute larger well pads that are rapidly
becoming the industry norm today
• Results in major cost savings for E&P operators
• In an environment where total operator spread costs can
approach $75,000/day on a wellsite, the incremental dayrate for
a pad-optimal rig is marginal
• In 2015, for a large E&P operator utilizing a pad drilling
program, ICD cut 70 days and $5.3MM off their original AFE
drilling budgets
$5.3MM (1)
86%
14%
Current or Recent ICD customers
High-Quality Customer Base
Company 2016E Total Capex ($MM)
Anadarko Petroleum Corporation 2,800
Pioneer Natural Resources 2,000
Apache Corporation 1,600
Devon Energy 1,308
Concho Resources 1,200
SM Energy 705
Cimarex Energy 675
Newfield Exploration 650
QEP Resources 475
Parsley Energy 405
Laredo Petroleum 345
Diamondback Energy 313
Energen Energy 300
RSP Permian 230
Approach Resources 50
BOPCO N/A
Elevation Resources N/A
Silver Hill Energy N/A
Source: Wall Street Consensus Estimates and Company Guidance as of April 7, 2016
ICD Customers Include Some of the Highest Quality,
Most Active Players in the Permian Basin
ICD has established a deep and high-quality customer base
composed of some of the most active players in the Permian
Basin
• ICD holds strong contract backlogs relative to peers in the land drilling
industry
– Backlog at 6/30/16: $48.5 million(1)
– $25.4 million extends beyond 2016
– Additional rigs working on short-term contracts with durations less
than six months
• ICD’s fleet standardization provides several benefits for customers
including consistent branding, predictability in performance and quick
understanding of the rig’s capabilities
• ICD is focused on strategically expanding its customer base
– Target customers with significant investments and willingness to drill
through industry cycles
– Target operators who value safety and efficient operations
– Focus on customers willing to enter into long-term contractual
relationships
11
ICD Customer Base Breakdown (2)
Publicly Traded
Private
1. Backlog does not include potential reductions in rates for periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of contractually allowed downtime. In addition, ICD currently expects that
several rigs under term contracts will realize revenue on a standby-without-crew basis, which preserves expected cash margins from the contract but reduces overall top line revenue included in backlog. To the extent that rigs under
term contracts operate on a standby or standby-without-crew basis, top line revenues will be less than reported backlog from term contracts.
2.. As of 6/30/2016
33%
67%
Significant Financial Flexibility
12
Cash and Cash equivalents 7.1
Long-Term Debt – Credit Facility(1) 16.4
Total ICD Stockholders’ Equity 273.2
Total Capitalization 289.6
Undrawn Revolver (2) 68.3
Available Liquidity (3) 75.4
Net Debt / LTM Adj. EBITDA (4) 0.36x
Total Debt / Total Capitalization 5.6%
($MM)
As of 6/30/2016
1. Excludes capitalized vehicle leases.
2. Reflects credit facility aggregate commitments of $85MM.
3. Available Liquidity = Cash + Available Revolver Capacity.
4. LTM Adjusted EBITDA as of 6/30/2016 of $25.9MM. See appendix for reconciliation of non-GAAP financial items
ICD Poised to Restart Growth When Market
Conditions Improve
ICD capital budget for the second half of 2016 is
approximately $10 million(1), including recently completed
projects relating to adding 7,500 psi mud systems/third
mud pumps and other additions to meet requirements of
new opportunities
ICD has already made significant investment towards its
final 100 Series upgrade and next two newbuild
ShaleDriller® rigs
• ICD estimates as of 12/31/16, an additional $25 million will
be required to complete these three capital projects.
Following completion of these projects, ICD fleet would be
comprised of 16 200 Series ShaleDriller® rigs
• Three month time period to complete each project
When market conditions improve, ICD is ideally positioned
to complete the next three planned capital projects while
still maintaining a very strong liquidity position
13
Financial Flexibility and Liquidity
1. Remaining budgeted 2016 capex as of 7/27/16 conference call, adjusted for additional rig reactivation during 3Q’16 and poten tial future investments for additional rig reactivations.
2. Incremental growth capex represents estimated costs to be incurred to complete final rig conversion and next two 200 Series ShaleDriller rigs as of 12/31/16.
3. LTM Adjusted EBITDA as of 6/30/2016 of $25.9MM, Assumes remaining/incremental capex funded with revolving credit facility borrowings. See appendix for reconciliation of non-GAAP financial items.
$MM
Cash @ 6/30/16 $7.1
Plus: Revolving Credit Facility Capacity @ 6/30/16 85.0
Less: Outstanding Borrowings @ 6/30/16 (16.4)
Total Liquidity $75.7
Less: Remaining 2016 capex 10.0
Incremental growth capex(2) 25.0
Total Liquidity Adjusted (3) $40.7
Adjusted Net Debt / LTM Adj. EBITDA (3) 1.7x
Adjusted Total Debt / Total Capitalization (3) 15.8%
Land Drilling’s Only
Pure-Play, Pad-optimal,
Growth Story
Large Operators are
Leading
Unconventional
Resource Capture
Major Secular Shift in
Unconventional
Development is
Underway
Ongoing Resource
Play Development
Driving a Rig
Replacement Cycle
Pad-optimal AC
Drilling Rigs are in
Short Supply
Major Barriers to
Entry Exist for New
Contract Drillers
Vertically Integrated
Model Provides a
Compounding Capital
Advantage
ShaleDriller® Offers a
Compelling Value
Proposition to E&P
Customers
ICD Provides a Differentiated Value
Proposition to E&P Operators
14
Non-GAAP Financial Measures
15
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. 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 permitted to be added back, subtracted from, net income for purposes of
calculating EBITDA under our revolving credit facility. Adjusted EBITDA is not a measure of net income as determined by U.S. generally accepted accounting principles ("GAAP").
Management believes Adjusted EBITDA is useful because it allows 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. We exclude the items listed above from net income (loss) in calculating 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
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 EBITDA are significant components in understanding and assessing a company's financial performance, such as a
company's cost of capital and tax structure, as well as stock-based compensation and the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our
presentation of 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 EBITDA may
not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income for each of the periods indicated:
June 30, 2016 June 30, 2015
March 31,
2016
June 30, 2016 June 30, 2015
(in thousands)
Net (loss) income $ (4,191) $ (652) $ (414) $ (4,605) $ 723
dd back:
I c m x xp (benefit) 31 95 4 35 (60)
Int rest xpe s 1,059 717 977 2,036 1,029
D pr i ion an mortization 5,816 5,169 5,825 11,641 9,458
E ITDA 2,715 5,329 6,392 9,107 11,150
Stock-based compensation 1,205 801 1,155 2,360 1,734
Stock-based compensation - executive retirement (67) - - (67) -
(Insurance recoveries) asset impairment, net - - - - (841)
Loss (gain) on disposition of assets 37 (59) (125) (88) 334
Executive retirement 1,552 - - 1,552 -
Adjusted EBITDA $ 5,442 $ 6,071 $ 7,422 $ 12,864 $ 12,377
(Unaudited)
Six Months EndedThree Months Ended
(Unaudited)
178
178
178
178
210
224
38
84
124
110
0
50
0
62
126
0
32
96
16