IT'S ABOUT PERFORMANCE
Corporate
Presentation
Certain information in this document is forward-looking and is subject to
important risks and uncertainties. The results or events predicted in this
information may differ from actual results or events.
Factors which could cause actual results or events to differ materially from
current expectations include, among other things, the ability of Trinidad Drilling
Ltd. to successfully implement its strategic initiatives and whether such strategic
initiatives will yield the expected benefits, the availability and price of energy
commodities, regulatory environment, competitive factors in the natural gas
transportation and natural gas liquids extraction industries and the prevailing
economic conditions in North America.
For additional information on these and other factors, see the reports filed by
Trinidad Drilling Ltd. with Canadian securities regulators. Trinidad Drilling Ltd.
disclaims any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise.
Trinidad has:
−
High quality fleet
−
Diversified operations
−
Solid plan for the downturn; well positioned
for the rebound
−
International expansion opportunities
−
Improved liquidity
Operations Overview
IT'S ABOUT PERFORMANCE
Canada
82 rigs
US
70 rigs
2 barges
Mexico*
6 rigs
Saudi
*
4 rigs
Rig Manufacturing
Innovation & Design
UAE
─
Canada – activity remains weak compared to
prior years
─
US – activity stalled, new opportunities on hold
─
Competition strong, with pressure on dayrates
─
Early termination of contracts slowed
Industry Active Rig Counts
─
North American activity below previous lows
─
Volatility impacting E&Ps budgeting ability
─
Cost structure being re-set across the industry
0
200
400
600
800
1000
1 4 7 10 13 16 19 22 25 8 2 31 34 37 0 4 43 46 49 52
Canadian Industry Active Rig Count
5 year range
2009
2014
2015
500
1000
1500
2000
2500
0 1 0 4 0 7 1 0 1 3 1 6 1 9 2 2 2 5 2 8 3 1 3 4 3 7 4 0 4 3 4 6 4 9 5 2US Industry Active Rig Count
─
Effective date August 11, 2015
─
Overwhelming approval from shareholders
−
>95% approval from >60% of all outstanding
shareholders
─
Issued 88.7 million shares and $50 million in cash
−
Total shares outstanding now 222.1 million
─
Integration underway, synergy identification and
process alignment in progress
─
Greater scale to capitalize on opportunities
─
Larger, more diverse fleet with industry-leading activity
─
Savings through increased scale and operating
efficiencies
─
Expanded management team and board of directors
provide improved leadership and guidance
─
Lower leverage metrics
─
Increased market liquidity, improved cost of capital
and future access to capital
Trinidad’s Canadian Operations
Liard
Montney
Oil sands
Frobisher Duvernay
Cardium AB Bakken
Key Operating Areas
Lloyd Heavy Oil
−
Active in key plays
−
Consistent industry-leading
activity
−
Customers waiting to
commit to rigs
−
Activity low by historical
─
Tele-double rigs the most active rigs in Canada
−
Mechanical rigs with high hookload and large pumps
─
AC rigs make up approx. 10-15%
(1)
of Canadian market
─
Trinidad’s Canadian fleet has the right specifications
−
Average depth ~6,000m (20,000 ft)
(2)
−
Average hookload ~185,000daN (416,000 lbs)
−
Average horsepower ~827 HP
Different Markets, Different Needs
Trinidad’s rigs remain more active
(1) Source: Estimates from CAODC data (2) Assumes horizontal depth capacity
Trinidad’s United States Operations
Bakken
Permian
Eagle Ford
Barnett Haynesville Tuscaloosa
Mississippi Lime
Key Operating Areas
Eaglebine Niobrara
−
US operations less seasonal
−
Dayrates and activity remain
under pressure
−
Customers waiting to commit
─
US customers focused on efficiency gains
from technology
─
AC rigs, preferably with moving systems and large
pumps the rig of choice
─
Trinidad known in the US for its high performance,
AC powered rigs
─
Approximately 50% of Trinidad’s US fleet is AC rigs
Trinidad’s International Operations
Mexico
Key Operating Areas
Saudi
−
Joint venture with
Halliburton
(1)
(60/40 Split)
−
Combines customer
relationships and
operational excellence
−
Growing international joint
venture contribution
−
Less affected by volatile
commodity prices
UAEHAL Joint Venture – Saudi
─
Four rigs currently operating in Ghawar field
─
2015 is first full year of operations
─
Costs lowering as operations grow
─
Drilling efficiencies have improved
−
40% increase in well delivery performance from first
year of Saudi operations
─
Construction of new builds complete
─
Three rigs working; one receiving standby
─
New builds performance exceeding expectations
“In Mexico, we completed drilling the first well using rigs
from our joint venture with Trinidad Drilling, setting a new
drilling record for South Mexico Mesozoic basin.”
Jeffrey Allen Miller, Halliburton President, Director & Chief Health, Safety and Environment Officer
– Excerpt from Q2 2015 conference call
Joint Venture – International Growth
─
Replace existing rigs
─
Supply high
specification rigs for
new projects
−
Can be new builds or
existing Trinidad rigs
−
Potential opportunities
exist for CanElson rigs
0 400 800 1,200 1,600 2,000 2,400 2,800 0 5 10 15 20 25 30 35 40 45 50 55 60 65 US TDG US
US Average Active Rig Count
Source – Bloomberg US Baker Hughes Rig Counts, Company Reports – excludes rigs on Standby
Consistent Industry Outperformance
Trinidad’s Canadian
Utilization
Trinidad’s rigs are
more active
Industry Average
Trinidad’s US
Average Active Rig Count
Industry Average
Active
Rig Count
0% 10% 20% 30% 40% 50% 60% 70%Canadian Utilization Rates
Deep and Modern Fleet
In Demand Specifications
70%
23%
7%
Tier 1 - High Hookload, Top Drive, Large Mud
Pumps
Tier 2 - Must have two of the three (High Hookload,
Top Drive, Large Mud Pumps)
Rig Fleet Horizontal Depth
10%
22%
68%
0 - 11,999 ft
12,000-17,999 ft
18,000+ ft
Rig Fleet Age
In-demand rigs generate higher dayrates and margins
26%
51%
23%
< 5 years
5-10 years
> 10 years
─
Highly variable cost structure
−
Field labour fluctuates with activity
─
Lower overhead costs
−
Reduction in salaried headcount
−
Wage rollbacks
─
Cost reduction strategies with suppliers
─
Reduced capital budget
Conservative Capital Program
─
Complete US new builds
─
Complete Mexico JV rigs
─
Select upgrades /
maintenance capital /
capital inventory
$60
$34
$39
$12
$40
2015 Capital Program ($mm)
New Builds
Upgrades
Capital Inventory
Maintenance
Joint Venture
(1)2015 Capital Budget – $185 million
(1)(2)
Customer Backed Growth
─
We only build rigs under
long-term contracts
─
Approximately 35% of
fleet on long-term
contract
─
Approximately 1.5 years
─
Lower leverage following CanElson acquisition
─
Funds available on credit lines
─
Pro Forma Q2 2015 Debt/EBITDA at 1.85
(1)
times
−
Outstanding debt largely non-covenant debt
−
Can use CanElson’s trailing 12 months in covenant
calculation
−
Covenant relief for Q4 2015 and Q1 2016 of 0.5
times (to 4.5 times as part of the acquisition)
When market conditions improve Trinidad has:
─
Expertise, customer base and track record to
capture North American market share
─
A good vehicle for international growth through its
joint venture
─
Independent international opportunities
−
Potential opportunities exist for CanElson rigs
Skilled crews drive improved performance and
customer demand
─
Experienced, well-trained people our biggest asset
─
Competency training program implemented
─
Industry leading safety processes
─
Retain experienced people through the downturn
─
Long term leverage target of 1.5 times debt/EBITDA
─
Review ways to lower leverage
−
Grow EBITDA base
−
Reduce future capital budgets, pursue only high
return projects
−
Sell additional assets to the JV (40% of value repaid)
−
Review all costs and cash outflows
─
Strategic capital allocation
Trinidad has:
−
High quality fleet
−
Diversified operations
−
Solid plan for the downturn; well positioned for
the rebound
−
International expansion opportunities
−
Improved liquidity
IT'S ABOUT PERFORMANCE
Second Quarter Financial Highlights
(3)
(1) Readers are cautioned that Operating income, Operating income percentage, Operating income - net percentage, EBITDA, Adjusted EBITDA, Funds provided by operations, Adjusted net (loss) earnings and the related per share information do not have standardized meanings prescribed by IFRS – see “Non-GAAP Measures” and “Additional GAAP Measures”.
(2) Basic shares include the weighted average number of shares outstanding over the period. Diluted shares include the weighted average number of shares outstanding over the period and the dilutive impact, if any, of the number of shares issuable pursuant to the Incentive Option Plan.
(3) Excludes CanElson
($ tho usands except share and per share data) 2015 2014 % Cha nge 2015 2014 % Cha nge Revenue 95,213 168,945 (43.6) 289,609 420,450 (31.1) Revenue, net of thi rd pa rty cos ts 89,992 159,644 (43.6) 276,071 390,662 (29.3) Opera ting i ncome (1) 41,896 45,605 (8.1) 114,178 140,797 (18.9) Opera ting i ncome percentage (1) 44.0% 27.0% 63.0 39.4% 33.5% 17.6 Opera ting i ncome - net percentage (1) 46.3% 28.3% 63.6 41.1% 35.9% 14.5 EBITDA (1)
27,686
5,445 408.5 79,210 86,700 (8.6) Per s ha re (di l uted) (2) 0.21 0.04 425.0 0.59 0.62 (4.8) Adjus ted EBITDA (1)
34,679
30,644 13.2 94,708 110,086 (14.0) Per s ha re (di l uted) (2) 0.26 0.22 18.2 0.71 0.79 (10.1) Ca s h provi ded by opera tions 113,621 71,086 59.8 114,549 90,519 26.5
Per s ha re (ba s i c / di l uted) (2) 0.85 0.51 66.7 0.86 0.65 32.3 Funds provi ded by opera tions (1)
25,132
30,285 (17.0) 61,224 91,142 (32.8) Per s ha re (ba s i c / di l uted) (2) 0.19 0.22 (13.6) 0.46 0.66 (30.3) Net (l os s ) ea rni ngs (1,467) (24,815) 94.1 10,663 947 1,026.0
Per s ha re (ba s i c / di l uted) (2) (0.01) (0.18) 94.4 0.08 0.01 700.0 Adjus ted net (l os s ) ea rni ngs (1) (297) (5,557) 94.7 17,728 22,189 (20.1)
Per s ha re (ba s i c / di l uted) (2) - (0.04) - 0.13 0.16 (18.8) Ca pi tal expendi tures 41,794 71,587 (41.6) 91,928 102,793 (10.6) Di vi dends decl a red 6,671 6,910 (3.5) 13,343 13,818 (3.4) Sha res outs tandi ng - di l uted
(wei ghted a vera ge) (2)
133,425,344 138,873,120 (3.9) 133,559,340 138,848,922 (3.8)
As at June 30, December 31,
($ tho usands except percentage data) 2015 2014 % Cha nge Total a s s ets 2,024,223 1,941,621 4.3 Total l ong-term l i a bi l i ties 738,737 628,047 17.6
─
Debt/EBITDA at 1.85
(1)
times at Q2 2015
─
Debt covenants
−
Debt/EBITDA max of 4.0 times
(relief to 4.5 times, after acquisition)
(2)
−
Senior Debt/EBITDA max of 3.0 times
−
EBITDA/Cash Interest Expense min of 2.75 times
Debt Overview
Credit Facility
Available
Outstanding
Q2 2015
Expiry
Revolver
C$200 m
US$200 m
C$69.9 m
US$0 m
Dec 2018
US$ Senior Notes (7. 785%)
US$450 m
US$450 m
Jan 2019
Total Long-term Debt
C$623 m
Historical Dayrates
(1)
0% 10% 20% 30% 40% 50% 60% $0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000US Rate Per Operating Day vs Operating Margin
Rate per operating day Operating margin
Dayrates ($US) 0% 10% 20% 30% 40% 50% $0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000
Canada Rate Per Operating Day vs Operating Margin
Rate per operating day Operating margin
Dayrates ($CDN) 0% 10% 20% 30% 40% 50% $0 $10,000 $20,000 $30,000 $40,000 $50,000 $60,000
JV Rate Per Operating Day vs Operating Margin
Rate per operating day Operating margin
Dayrates ($US)
Combined Fleet Expands Diversity
MEXICO
CANADA
US
MIDDLE EAST
TDG Operating Area
Liard Montney
Duvernay
Cardium Heavy OilLloyd Oil sands AB Bakken Bakken Niobrara Haynesville Barnett Eagle Bine Mississippi Lime Permian Tuscaloosa Eagle Ford
JV and partnership rigs included at 100%, excludes barge and service rigs
Canada
US
Int'l
Total
Trinidad Rigs
54
50
8
112
CanElson Rigs
28
21
2
51
Total
82
71
10
163
Woodford Deep Basin
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
TRIF
Total Recordable Incident Rates
A Continued Focus on Safety
TRIF – Total Recordable Injury Frequency, 12 month corporate rolling average Aug 2015 – Pro forma
This document contains references to certain financial measures and associated per share data that do not have any standardized meaning prescribed by IFRS and may not be comparable to similar measures presented by other companies. These financial measures are computed on a consistent basis for each reporting period and include Adjusted EBITDA, Total Debt to EBITDA, drilling days, operating days, utilization rate -drilling day, utilization rate - operating day, and rate per operating day. These non-GAAP measures are identified and defined as follows: “Adjusted EBITDA” is used by management and investors to analyze EBITDA (as defined above) prior to the effect of foreign exchange, share-based payment expense, impairment expenses and the sale of assets. Adjusted EBITDA also takes into account the Company’s portion of the principal activities of the joint venture arrangement by removing the loss (gain) from investment in joint venture and including EBITDA from investment in joint venture. Adjusted EBITDA is not intended to represent net earnings as calculated in accordance with IFRS. Adjusted EBITDA provides an indication of the results generated by the Company’s principal business activities prior to how these activities are financed, assets are depreciated, amortized and impaired, the impact of foreign exchange, how the results are taxed in various jurisdictions and effects of share-based payment expenses.
“Total Debt to Bank EBITDA” is defined as the consolidated balance of long-term debt, which includes the Senior Debt, Senior Notes Payable and dividends payable at quarter end, to consolidated Bank EBITDA for the TTM. Bank EBITDA used in this financial ratio is calculated as EBITDA plus impairment expense, loss (gain) on sale of property and equipment, loss (gain) from investment in joint venture, share-based payment expense and unrealized foreign exchange.
“Drilling days” is defined as rig days between spud to rig release.
“Operating days” is defined as moving days (move in, rig up and tear out) plus drilling days (spud to rig release). “Utilization rate - drilling day” is defined as drilling days divided by total available rig days.
“Utilization rate - operating day” is defined as operating days (drilling days plus moving days) divided by total available rig days.
“Rate per operating day” or “Dayrate” is defined as operating revenue (net of third party costs) divided by operating days (drilling days plus moving days).
“Payout level” is defined as annual dividends declared divided by annual funds provided by operations.
Non-GAAP Measures Definitions
The Company uses certain additional GAAP financial measures within the financial statements and this document that are not defined terms under IFRS to assess performance. Management believes that these measures provide useful supplemental information to investors, and provide the reader a more accurate reflection of our industry. These financial measures are computed on a consistent basis for each reporting period and include Funds provided by operations, Operating income and Operating income - net percentage or Operating margin. These additional GAAP measures are identified and defined as follows:
“Funds provided by operations” is used by management and investors to analyze the funds generated by Trinidad’s principal business activities prior to consideration of working capital, which is primarily made up of highly liquid balances. This balance is reported in the Consolidated Statements of Cash Flows included in the cash provided by operating activities section.
“Operating income” is used by management and investors to analyze overall and segmented operating performance. Operating income is not intended to represent an alternative to net earnings or other measures of financial performance calculated in accordance with IFRS. Operating income is calculated from the consolidated statements of operations and comprehensive income (loss) and from the segmented information contained in the notes to the consolidated financial statements. Operating income is defined as revenue less operating expenses.
“Operating income - net percentage” or “operating margin” is used by management and investors to analyze overall and segmented operating performance excluding third party recovery and third party costs, as well as inter-segment revenue and inter-segment operating costs, as these revenues and expenses do not have an effect on consolidated net earnings. Operating income - net percentage is calculated from the
consolidated statements of operations and comprehensive income (loss) and from the segmented information in the notes to the consolidated financial statements. Operating income - net percentage is defined as operating income less third party G&A expenses divided by revenue net of operating and G&A third party costs.
