2016 Jan Trinidad Presentation
description
Transcript of 2016 Jan Trinidad Presentation
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IT'S ABOUT PERFORMANCE 1
IT'S ABOUT PERFORMANCE
AltaCorp Conference
January 12, 2016
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IT'S ABOUT PERFORMANCE 2
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.
Forward Looking Information
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Trinidad has:
High quality fleet
Diversified operations
Solid plan for the downturn; well positioned for the rebound
International expansion opportunities
Improved liquidity
Why Invest In Trinidad
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IT'S ABOUT PERFORMANCE 4
Operations Overview
IT'S ABOUT PERFORMANCE
Canada82 rigs US
71 rigs 2 barges
Mexico*6 rigs
Saudi*4 rigs
* Rigs operating under the JV included at 100 percent; does not include DCM service rigs
Rig Manufacturing Innovation & Design
UAE1 rig
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North American Industry Update
North American activity below previous lows
Strong competition and downward pressure on dayrates
Cost structure being re-set across the industry
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Canadian Industry Active Rig Count
5 year range 2009 2014 2015
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US Industry Active Rig Count
5 year range 2009 2014 2015
Source: Bloomberg Baker Hughes Oil and Gas Rotary Rig Count
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Trinidad Update
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Overwhelming approval from shareholders
Total consideration paid $345 million ($50m cash, 88.7m shares)
Integration to be largely complete by year end
Larger, more diverse fleet with industry-leading activity
Savings through increased scale and operating efficiencies
Lower leverage metrics
Increased market liquidity, improved cost of capital and future access to capital
CanElson Acquisition Update
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Trinidads Canadian Operations
Liard
Montney
Oilsands
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 levels
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Trinidads 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 to rigs
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HAL Joint Venture Saudi
Four rigs currently operating in Ghawar field
2015 - first full year of operations
Costs lowering, drilling efficiencies improving
Saudi activity levels stronger than North America
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120 Saudi Industry Average Active Rig Count
Source Baker Hughes International Rig Counts
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Four rigs working; performance exceeding expectations
Largest, most technically advanced rigs in country
HAL Joint Venture Mexico
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Mexico Average Active Rig Count
Source Baker Hughes International Rig Counts
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Strong performance leads to opportunities:
Replace existing rigs as contracts expire
Supply high spec rigs for new projects
new builds or existing idle equipment
Ability to bring back the cash from the joint venture:
Q3 2015 adjusted EBITDA of $8 million
Q3 2015 accumulative adjusted EBITDA of $21 million
Growth opportunities through the joint venture and independently
Future International Growth
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Short Term Plan for the Downturn
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65US TDG US
US Average Active Rig Count
Source Bloomberg US Baker Hughes Rig Counts, Company Reports excludes rigs on Standby
Consistent Industry Outperformance
Trinidads Canadian Utilization
Trinidads rigs are more active
Trinidads US Average Active Rig Count
Industry Average Active
Rig Count
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Canadian Utilization Rates
Source Canadian Association of Oil Well Drilling Contractors
Industry Average
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Deep and Modern Fleet
In Demand Specifications
70%
23%
7%
Tier 1 - High Hookload, Top Drive, Large MudPumps
Tier 2 - Must have two of the three (High Hookload,Top Drive, Large Mud Pumps)
Tier 3 - Mechanical Rigs, Lower HP, Lower Hookload
Rig Fleet Horizontal Depth
10%
23%
67%0 - 11,999 ft
12,000-17,999 ft
18,000+ ft
Rig Fleet Age
In-demand rigs generate higher dayrates and margins
Land drilling rigs only
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52%
27%
< 5 years
5-10 years
> 10 years
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Synergies and cost cutting measures approximately $30 mm, original estimate of $10 mm
Highly variable cost structure
Field labour fluctuates with activity
Total headcount down approximately 50%, combined with wage rollbacks
2015 G&A $60 million, down 30% from projected
2016 G&A expected to be $50 - $55 million
Reduced capital budget
Reduced Cost Structure
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Adaptable Capital Spending
Focused on capital maintenance and infrastructure projects
Additional $15 million available for select upgrades, depending on industry conditions
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$mm Capital Spending
2016 Capital Budget $30 million
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Contract Coverage Still Strong
Over 25% of fleet on long-term contract
We only build rigs under long-term contracts
Approx. 1.5 years average term remaining
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Funds available on credit lines (C$115m/US$200m)
Q3 2015 Debt/EBITDA at 2.65 times (2.37 times incl. accumulative JV EBITDA)
Outstanding debt largely non-covenant debt
CanElsons trailing 12 months included in calculation
Ability to bring cumulative JV EBITDA back
Debt covenants relaxed through 2017
Improved Liquidity
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Debt covenant changes
Debt/EBITDA max of 6.0 times until March 31, 2017, gradually reverts to 4.0 times in 2018
EBITDA/Cash Interest Expense min of 2.0 times until end of 2017, at 2.5 times thereafter
Debt Covenant Changes & Overview
Credit Facility Available Outstanding Q3 2015
Expiry
Revolver C$150 mUS$150 m
C$84.9 mUS$0 m
Dec 2018
US$ Senior Notes (7. 785%) US$450 m US$450 m Jan 2019
Total Long-term Debt C$682 m
Cash on Hand C$24.7 m
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Long Term Strategy
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When market conditions improve, Trinidad has:
Expertise, customer base and track record to capture North American market share
A good vehicle for international growth through its joint venture
Independent international opportunities
Future Growth Opportunities
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Skilled crews drive improved performance and customer demand:
Experienced, well-trained people our biggest asset
Competency training program implemented
Industry leading safety processes
Retain experienced people through the downturn
Investing in People and Safety
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Trinidad has:
High quality fleet
Diversified operations
Solid plan for the downturn; well positioned for the rebound
International expansion opportunities
Improved liquidity
Why Invest In Trinidad
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IT'S ABOUT PERFORMANCE
APPENDIX
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Third Quarter Financial Highlights(3)
(1) Readers are cautioned that Operating income, Operating income percentage, Operating income - net percentage, EBITDA, Adjusted EBITDA, Funds provided by operations, Adjusted net (loss) earnings and the related per share information do not have standardized meanings prescribed by IFRS see Non-GAAP Measures and Additional GAAP Measures.
(2) Basic shares include the weighted average number of shares outstanding over the period. Diluted shares include the weighted average number of shares outstanding over the period and the dilutive impact, if any, of the number of shares issuable pursuant to the Incentive Option Plan.
(3) Excludes CanElson
($ thousands except share and per share data) 2015 2014 % Change 2015 2014 % Change
Revenue 124,285 244,538 (49.2) 413,894 664,988 (37.8)
Revenue, net of third party costs 117,824 230,985 (49.0) 393,895 621,647 (36.6)
Operating income (1) 52,009 80,536 (35.4) 166,187 221,333 (24.9)
Operating income percentage (1) 41.8% 32.9% 27.1 40.2% 33.3% 20.7
Operating income - net percentage (1) 43.9% 34.7% 26.5 41.9% 35.4% 18.4
EBITDA (1) (99,112) 67,207 (247.5) (19,902) 153,907 (112.9)
Per share (di luted) (2) (0.54) 0.48 (212.5) (0.13) 1.11 (111.7)
Adjusted EBITDA (1) 44,953 64,619 (30.4) 139,660 174,706 (20.1)
Per share (di luted) (2) 0.25 0.47 (46.8) 0.93 1.26 (26.2)
Cash provided by operations (5,640) 60,143 (109.4) 108,909 150,662 (27.7)
Per share (bas ic / di luted) (2) (0.03) 0.44 (106.8) 0.73 1.09 (33.0)
Funds provided by operations (1) 16,392 46,554 (64.8) 77,616 137,696 (43.6)
Per share (bas ic / di luted) (2) 0.09 0.34 (73.5) 0.52 0.99 (47.5)
Net (loss ) earnings (87,618) 19,156 (557.4) (76,955) 20,103 (482.8)
Per share (bas ic / di luted) (2) (0.48) 0.14 (442.9) (0.51) 0.15 (440.0)
Adjusted net earnings (1) 1,014 14,602 (93.1) 18,750 36,791 (49.0)
Per share (bas ic / di luted) (2) 0.01 0.11 (90.9) 0.12 0.26 (53.8)
Capita l expenditures 21,628 100,453 (78.5) 113,556 203,246 (44.1)
Dividends declared 11,104 6,910 60.7 24,447 20,728 17.9
Shares outstanding - bas ic
(weighted average) (2) 182,574,890 138,195,784 32.1 150,077,401 138,168,514 8.6
Shares outstanding - di luted
(weighted average) (2) 182,574,890 138,664,015 31.7 150,077,401 138,854,145 8.1
As at September 30, December 31,
($ thousands except percentage data) 2015 2014 % Change
Total assets 2,372,949 1,941,621 22.2
Total long-term l iabi l i ties 811,101 628,047 29.1
Three months ended September 30, Nine months ended September 30,
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Trinidads International Operations
Mexico
Key Operating Areas
Saudi
Joint venture in Saudi Arabia and Mexico with Halliburton(1) (60/40 split)
Joint venture in Mexico with DCM (50/50 split)
Less affected by volatile commodity prices
(1) Halliburton Project Management with 40% interest
UAE
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Credit Agreement Amendment
Current Credit Agreement Previous Credit Agreement
Credit Facility Size
Canadian Tranche C$150 million C$200 million
US Tranche US$150 million US$200 million
Credit Facility Covenants
Total Leverage CovenantTotal Debt/ Bank EBITDA (1) (2)
Maximum of 6.0x Jan 01 2016 to Mar 31 2017Maximum of 5.5x Apr 01 2017 to Jun 30 2017 Maximum of 5.0x Jul 01 2017 to Dec 31 2017Maximum of 4.0x Jan 01 2018 on
Maximum of 4.0x
Interest CoverageBank EBITDA(1)/ Cash Interest Expense
Minimum of 2.0x Jan 01 2016 to Dec 31 2017Minimum of 2.5x Jan 01 2018 on
Minimum of 2.75x
Dividend Restriction (3) Maximum of $0.01 per share per quarter if Total Leverage Covenant is greater than 5.0 times
No such restriction
(1) See Non- GAAP disclaimer at the end of this document.(2) The ability to step the covenant up by 0.5 times for the two quarters following a material acquisition has been removed.(3) Restricted payments (including dividends) remain unchanged at a maximum of 60% of last 12 months excess cash flow (as defined in the credit agreement).Note: Senior Debt covenant (as defined in the credit agreement) remains unchanged at a maximum of 3.0 times.
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Historical Dayrates(1)
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US Rate Per Operating Day vs Operating Margin
Rate per operating day Operating margin
Dayrates($US)
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Canada Rate Per Operating Day vs Operating Margin
Rate per operating day Operating margin
Dayrates($CDN)
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Halliburton JV Rate Per Operating Day vs Operating Margin
Rate per operating day Operating margin
Dayrates($US)
(1) Excludes CanElson
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Combined Fleet Expands Diversity
MEXICO
CANADA
US
MIDDLE EAST
TDG Operating Area
Mutual Operating Area
Liard
Montney
Duvernay
CardiumLloyd
Heavy Oil
Oil sands
AB Bakken Bakken
Niobrara
Haynesville
Barnett
Eagle Bine
Mississippi Lime
Permian
Tuscaloosa
Eagle FordJV and partnership rigs included at 100%, excludes service rigs
Canada US & Int'l JV's Total
Trinidad Rigs 54 51 8 113
CanElson Rigs 28 21 2 51
Total 82 72 10 164
Woodford
Deep Basin
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TRIF
Total Recordable Incident Rates
A Continued Focus on Safety
TRIF Total Recordable Injury Frequency, 12 month corporate rolling averageStarting August 2015 Pro forma
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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 Companys 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 Companys 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.
Cash-on-cash yield is defined as annual dividends declared per share divided by the current share price.
Free Cash Flow is defined as annual funds provided by operations minus the sum of annual dividends declared and annual capital expenditures.
Non-GAAP Measures Definitions
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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 Trinidads 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.
Addl GAAP Measures Definitions
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IT'S ABOUT PERFORMANCE
1000, 585 8 Avenue S.W. Calgary, AB, Canada | T2P 1G1
T 403.265.6525
Email: [email protected]