2016 Jan Trinidad Presentation

IT'S ABOUT PERFORMANCE 1

IT'S ABOUT PERFORMANCE

AltaCorp Conference

January 12, 2016


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


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


Operations Overview


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


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

Trinidad Update


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


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


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


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


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


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

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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10%

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60%

70%

Canadian Utilization Rates

Source Canadian Association of Oil Well Drilling Contractors

Industry Average


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

20%

52%

27%

< 5 years

5-10 years

> 10 years


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


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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2016 Capital Budget $30 million


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


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


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

Long Term Strategy


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


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


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



APPENDIX


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,


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


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.


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


Dayrates($CDN)

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Halliburton JV Rate Per Operating Day vs Operating Margin


Dayrates($US)

(1) Excludes CanElson


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


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


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



1000, 585 8 Avenue S.W. Calgary, AB, Canada | T2P 1G1

T 403.265.6525

Email: [email protected]

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2016 Jan Trinidad Presentation