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TSX SYMBOL:  TDG

CALGARY, Aug. 4, 2015 /CNW/ - Trinidad Drilling Ltd. ("Trinidad" or the "Company") reported second quarter and year-to-date 2015 results. Weak commodity prices led to lower activity levels and reduced customer demand in the second quarter and first half of 2015. Despite these weak industry conditions, Trinidad was able to maintain operating margins and adjusted EBITDA was higher than the previous year, as the Company's contract base provided some protection against lower activity levels and the impact of cost reductions became more evident. The early termination and standby revenue received in the quarter postively impacted Trinidad's operating margins. In addition, Trinidad's geographic diversification helped mitigate the impact of a weak spring break-up in Canada.

"The past six months have been a challenging time in the oilfield services industry," said Lyle Whitmarsh, Trinidad's Chief Executive Officer. "Despite these weak industry conditions, Trinidad recorded higher operating margins and adjusted EBITDA in the second quarter of 2015 than the previous year. We reacted quickly to lower commodity prices and reduced customer demand early in 2015. The impact of the cost reduction measures we implemented, the strength of our long-term contracts and our reputation for top performance showed strongly in our second quarter results. During the quarter, we also took advantage of lower asset values and chose to add to Trinidad's fleet with the proposed strategic acquisition of CanElson Drilling Inc. (CanElson).  Combining our operations with CanElson's will create a larger, more diverse fleet that can meet the varied needs of our customers. It will expand Trinidad's management team and customer base, lower corporate leverage and provide an increased cash flow base to take advantage of growth opportunities. We believe that as a combined entity, we will be well positioned to weather the current downturn and to take advantage of opportunities once better conditions return."

(1)	See Non-GAAP Measures Definitions and Additional GAAP Measures Definitions section at the end of this document for further details.

FINANCIAL HIGHLIGHTS

		Three months ended June 30,			Six months ended June 30,
($ thousands except share and per share data)		2015	2014	% Change	2015	2014	% Change
Revenue		95,213	168,945	(43.6)	289,609	420,450	(31.1)
Revenue, net of third party costs		89,992	159,644	(43.6)	276,071	390,662	(29.3)
Operating income (1)		41,896	45,605	(8.1)	114,178	140,797	(18.9)
Operating income percentage (1)		44.0%	27.0%	63.0	39.4%	33.5%	17.6
Operating income - 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 share (diluted) (2)	0.21	0.04	425.0	0.59	0.62	(4.8)
Adjusted EBITDA (1)		34,679	30,644	13.2	94,708	110,086	(14.0)
	Per share (diluted) (2)	0.26	0.22	18.2	0.71	0.79	(10.1)
Cash provided by operations		113,621	71,086	59.8	114,549	90,519	26.5
	Per share (basic / diluted) (2)	0.85	0.51	66.7	0.86	0.65	32.3
Funds provided by operations (1)		25,132	30,285	(17.0)	61,224	91,142	(32.8)
	Per share (basic / diluted) (2)	0.19	0.22	(13.6)	0.46	0.66	(30.3)
Net (loss) earnings		(1,467)	(24,815)	94.1	10,663	947	1,026.0
	Per share (basic / diluted) (2)	(0.01)	(0.18)	94.4	0.08	0.01	700.0
Adjusted net (loss) earnings (1)		(297)	(5,557)	94.7	17,728	22,189	(20.1)
	Per share (basic / diluted) (2)	-	(0.04)	-	0.13	0.16	(18.8)
Capital expenditures		41,794	71,587	(41.6)	91,928	102,793	(10.6)
Dividends declared		6,671	6,910	(3.5)	13,343	13,818	(3.4)
Shares outstanding - diluted
	(weighted average) (2)	133,425,344	138,873,120	(3.9)	133,559,340	138,848,922	(3.8)
As at					June 30,	December 31,
($ thousands except percentage data)					2015	2014	% Change
Total assets					2,024,223	1,941,621	4.3
Total long-term liabilities					738,737	628,047	17.6

(1)

Readers are cautioned that Operating income, Operating income percentage, Operating income - net percentage, EBITDA, Adjusted EBITDA, Funds provided by operations, Adjusted net earnings and the related per share information do not have standardized meanings prescribed by IFRS - see Non-GAAP Measures Definitions and Additional GAAP Measures Definitions at the end of this document for further details.

(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.

OPERATING HIGHLIGHTS

			Three months ended June 30,			Six months ended June 30,
			2015	2014	% Change	2015	2014	% Change
Land Drilling Market
Operating days (1)
	Canada		380	1,430	(73.4)	2,723	5,507	(50.6)
	United States and International		2,202	4,441	(50.4)	4,897	8,752	(44.0)
Rate per operating day (1)
	Canada (CDN$)		31,731	26,338	20.5	26,597	25,655	3.7
	United States and International (CDN$)		33,184	22,890	45.0	33,188	23,747	39.8
	United States and International (US$)		26,755	20,819	28.5	27,318	21,716	25.8
Utilization rate - operating day (1)
	Canada		8%	26%	(69.2)	29%	50%	(42.0)
	United States and International		50%	80%	(37.5)	55%	78%	(29.5)
Number of drilling rigs at period end (3)
	Canada		54	59	(8.5)	54	59	(8.5)
	United States and International		49	56	(12.5)	49	56	(12.5)
Barge Drilling Market
	Operating days (1)		-	259	(100.0)	57	503	(88.7)
	Rate per operating day (CDN$) (1)		-	37,953	(100.0)	29,972	37,886	(20.9)
	Rate per operating day (US$) (1)		-	34,599	(100.0)	26,034	34,680	(24.9)
	Utilization rate - operating day (1)		0%	57%	(100.0)	9%	56%	(83.9)
	Number of barge drilling rigs at period end		2	2	-	2	2	-
	Number of barge drilling rigs under Bareboat
		Charter Agreements at period end	-	3	(100.0)	-	3	(100.0)
Joint Venture Operations (2)
	Operating days (1)		516			926
	Rate per operating day (CDN$) (1)		60,555			60,935
	Rate per operating day (US$) (1)		48,959			49,785
	Utilization rate - operating day (1)		95%			94%
	Number of drilling rigs at period end		8	4	100.0	8	4	100.0

(1)	See Non-GAAP Measures Definitions and Additional GAAP Measures Definitions section at the end of this document for further details.
(2)	Trinidad is party to a joint venture with a wholly-owned subsidiary of Halliburton. These rigs are owned by the joint venture. Operating data prior to 2015 has not been provided given the start-up nature of the operations.
(3)	Refer to the Results from Operations section for details on the changes to the rig count.

OVERVIEW

Trinidad reported improved adjusted EBITDA and net earnings (loss) in the second quarter of 2015 compared to the prior year, despite weaker market conditions and lower activity levels. Trinidad's strong contract base assisted in mitigating the impact of weaker customer demand and the Company's flexible cost structure and focus on cost containment helped maintain operating profitability during the second quarter.

In the second quarter and first half of 2015, adjusted EBITDA was $34.7 million and $94.7 million, respectively. Adjusted EBITDA increased by 13.2% in the quarter compared to the same period in 2014 as the impact of higher early termination and standby revenue and cost control measures implemented earlier in the year more than offset lower activity levels. In addition, Trinidad's international joint venture contributed higher adjusted EBITDA as a growing number of rigs generated revenue in the quarter. Year to date, adjusted EBITDA was down 14.0% in 2015 compared to the prior year due to lower activity levels across the Company's North American operations.

Trinidad recorded a net loss of $1.5 million or $0.01 per share - diluted in the quarter, an improvement of 94.1% from the same quarter last year largely as a result of higher adjusted EBITDA, no impairment of property and equipment and lower depreciation and share-based compensation expenses in the current period. Year to date in 2015, net earnings were $10.7 million or $0.08 per share - diluted, up 1,026.0% from the same period last year. Net earnings increased year to date as a result of the items impacting the current quarter and were further impacted by lower income taxes, partly offset by higher finance and transaction costs, and a smaller gain on sale of property and equipment in the current period.

On June 11, 2015, Trinidad and CanElson announced they had entered into an arrangement agreement to combine the two companies through a strategic business combination whereby Trinidad will acquire all of the issued and outstanding common shares of CanElson in exchange for a combination of cash (subject to a maximum cash payment of $50 million) and Trinidad common shares. As part of the transaction, Trinidad will assume the outstanding CanElson debt net of cash, which at June 30, 2015 was $18.9 million.  Information regarding the transaction has been mailed to shareholders of both companies, with shareholder meetings planned for August 10, 2015. Pending shareholder and regulatory approvals, the transaction is expected to close prior to the end of August 2015.

Crude oil prices improved slightly in the second quarter of 2015 from the first quarter but were low compared to the same period in 2014. Natural gas prices stabilized in the current quarter compared to the first quarter of 2015 but remained weak year over year. Continued weakness in commodity prices led to lower activity in the current quarter and year to date in 2015. Industry utilization in Canada lowered in the second quarter of 2015 as oil and gas developers took advantage of spring break-up to re-evaluate their capital programs. The active rig count in the US continued to lower in the second quarter; however, the magnitude of the weekly drops began to contract towards the end of the quarter. The slower downward momentum and a slightly improved crude oil price in the quarter led to initial signs of improved sentiment and growing belief that the industry may be at, or near, the bottom of the cycle. Since the end of the second quarter, commodity prices have weakened bringing uncertainty to the timing of a recovery in the industry.

INDUSTRY STATISTICS

	2015		Full Year	2014				Full Year	2013
	Q2	Q1	2014	Q4	Q3	Q2	Q1	2013	Q4	Q3
Commodity Prices
Aeco natural gas price (CDN$ per gigajoule)	2.54	2.60	4.28	3.44	3.82	4.45	5.34	3.01	3.33	2.32
Henry Hub natural gas price (US$ per mmBtu)	2.73	2.87	4.36	3.76	3.94	4.59	5.15	3.72	3.84	3.55
Western Canada Select crude oil price
(CDN$ per barrel)	59.40	43.52	82.00	65.42	85.68	91.34	85.81	75.84	69.62	86.31
WTI crude oil price (US$ per barrel)	57.85	48.49	93.06	73.21	97.60	103.06	98.72	98.01	97.56	105.82
Canadian / US dollar exchange rate	1.23	1.24	1.10	1.14	1.09	1.09	1.10	1.03	1.05	1.04
US Activity
Average industry active land rig count (1)	935	1,403	1,789	1,843	1,828	1,781	1,705	1,685	1,679	1,687
Average Trinidad active land rig count (2)	24	30	50	52	53	47	48	50	49	51
Canadian Activity
Average industry utilization (3)	13%	35%	44%	45%	46%	28%	58%	40%	43%	37%
Average Trinidad utilization (4)	7%	46%	52%	57%	61%	24%	68%	48%	48%	50%

(1)	Baker Hughes rig counts (information obtained from Tudor, Pickering, Holt & Co. weekly rig roundup report).
(2)	Includes US and international rigs.
(3)	Canadian Association of Oilwell Drilling Contractors (CAODC) utilization.
(4)	Based on drilling days (spud to rig release dates).

SECOND QUARTER AND YEAR-TO-DATE 2015 HIGHLIGHTS

• Adjusted EBITDA in the second quarter was $34.7 million and $94.7 million year to date in 2015, up 13.2% and down 14.0% from the same periods last year. The increase in the second quarter was largely the result of higher operating margins in the US and international division, increased activity in the joint venture and general and administrative savings, partly offset by lower activity in the Canadian and US operations driven by weakening commodity prices.  Lower adjusted EBITDA on a year-to-date basis was largely driven by lower activity in the Canadian and US operations.  The impact of lower activity was partly offset by higher early termination and standby revenue received in the US and international operations in the first half of 2015, compared to the prior year.
• Operating income - net percentage was 46.3% in the second quarter and 41.1% year to date for 2015, up from 28.3% and 35.9% for the same periods in 2014.  Operating income - net percentage increased as a result of higher early termination and standby revenue and cost cutting initiatives undertaken by Trinidad.  In addition, in the second quarter of 2015, there was lower manufacturing revenue than in the prior year. The manufacturing division typically generates lower margins than Trinidad's drilling operations as the external new builds are constructed for Trinidad's joint venture company and joint venture partner at cost plus a small margin.
• Net loss was $1.5 million for the second quarter compared to $24.8 million in the second quarter of 2014.  Net earnings were $10.7 million year to date for 2015 compared to $0.9 million in the prior year.  The increase in net earnings from the prior year was largely driven by impairment expense recognized in the prior year with no impairments recorded in 2015.  As well, the impact of higher early termination and standby revenue in the current quarter and cost savings initiatives instituted by Trinidad partly offset the effect of lower activity levels in the Canadian and US operations.  Lower general and administrative, depreciation and income tax expenses positively impacted net earnings for 2015.
• The Company's Manufacturing division delivered two high specification rigs to the US operations (one in each of the first and second quarters) along with completing work on the remaining two rigs for the joint venture operations in Mexico and the training rig for the Company's joint venture partner in the first quarter of 2015.
• In the second quarter, Trinidad and CanElson announced they had entered into an arrangement agreement to combine the two companies through a strategic business combination. Information regarding the transaction has been mailed to shareholders of both companies, with shareholder meetings planned for August 10, 2015. Pending shareholder and regulatory approvals, the transaction is expected to close prior to the end of August 2015.

RESULTS FROM OPERATIONS

Canadian Operations

	Three months ended June 30,				Six months ended June 30,
($ thousands except percentage and operating data)	2015	2014	% Change		2015	2014	% Change
Operating revenue (1)	12,061	37,681	(68.0)		72,431	141,288	(48.7)
Other revenue	28	358	(92.2)		73	1,080	(93.2)
	12,089	38,039	(68.2)		72,504	142,368	(49.1)
Operating costs (1)	8,775	28,724	(69.5)		43,597	83,024	(47.5)
Operating income (3)	3,314	9,315	(64.4)		28,907	59,344	(51.3)
Operating income - net percentage (3)	27.4%	24.5%			39.9%	41.7%
Operating days (3)	380	1,430	(73.4)		2,723	5,507	(50.6)
Drilling days (3)	349	1,318	(73.5)		2,484	5,031	(50.6)
Rate per operating day (CDN$) (3)	31,731	26,338	20.5		26,597	25,655	3.7
Utilization rate - operating day (3)	8%	26%	(69.2)		29%	50%	(42.0)
Utilization rate - drilling day (3)	7%	24%	(70.8)		26%	46%	(43.5)
CAODC industry average (2)	13%	28%	(53.6)		24%	42%	(42.9)
Number of drilling rigs at period end	54	59	(8.5)		54	59	(8.5)

(1)	Operating revenue and operating costs for the three months ended June 30, 2015 and 2014 exclude third party recovery and third party costs of $1.3 million and $4.9 million, respectively. Operating revenue and operating costs for the six months ended June 30, 2015 and 2014 exclude third party recovery and third party costs of $7.9 million and $19.5 million, respectively.
(2)	CAODC industry average is based on drilling days divided by total days available.
(3)	See Non-GAAP Measures Definitions and Additional GAAP Measures Definitions section at the end of this document for further details.

In the first half of 2015, crude oil prices remained weaker than the prior year and oil and gas producers maintained a conservative approach to capital spending.  This cautious outlook drove a shortened winter drilling season and considerably lower activity through spring break-up than in previous years.  Lower activity levels resulted in reduced operating days, utilization and operating income in Trinidad's Canadian division in the first half of 2015, compared to the same period last year.

Operating revenue for the second quarter and six months ended June 30, 2015, was $12.1 million and $72.4 million respectively, down 68.0% and 48.7% from the respective periods in 2014. Utilization and operating days lowered largely in line with the reduction in revenue; however, dayrates were higher, particularly for the second quarter, compared to the previous period.  The impact of an increased concentration of higher specification rigs working in the current periods offset the downward pressure on dayrates experienced to date in 2015.

Operating income - net percentage increased during the quarter to 27.4%, compared to 24.5% in the same quarter last year. Increased profitability in the current quarter reflected the impact of higher specification rigs which typically generate higher gross margins and management's cost containment initiatives, partly offset by lower activity levels and pressure from reduced customer demand.  Operating income - net percentage for the six months ended June 30, 2015, lowered to 39.9%, compared to 41.7% in the first half of 2014, as a result of lower activity levels and reduced customer demand.  With lower activity levels, the relatively fixed nature of operating support costs were spread over fewer operating days leading to some margin compression for the first half of the 2015.  Trinidad has continued to work with its suppliers to reduce costs in all aspects of its operations. As well, the Company continues to monitor repair and maintenance expenditures, incurring expenses on rigs only as they return to work.

In the second quarter of 2015, Trinidad had five fewer rigs compared to the second quarter of 2014.  In the second half of 2014, Trinidad transferred two rigs from the Company's US and international division to Canada and decommissioned eight rigs that were no longer competitive.  Trinidad added one new high specification rig in the first quarter of 2015.

Second quarter of 2015 versus first quarter of 2015

Operating revenue and operating income decreased by $48.3 million and $22.3 million, respectively, in the second quarter of 2015, compared to the first quarter of 2015.  The second quarter is typically affected by spring break-up, as weather conditions and road bans restrict the movement of heavy equipment, resulting in lower activity.  While oil prices recovered somewhat during the second quarter of 2015, they remained below the prior year, driving uncertainty in the industry, curtailed capital programs for exploration and development companies, and lower activity levels. Dayrates increased in the second quarter by 23.2% to $31,731 per day compared to the prior quarter due to an increased concentration of high specification rigs working, partly offset by lower customer demand. Operating margin - net percentage increased in the second quarter to 27.4% compared to 24.5% in the first quarter of 2015 as a result of higher dayrates and cost control programs implemented earlier in the year.

United States and International Operations

Three months ended June 30,   Six months ended June 30, ($ thousands except percentage and operating data) 2015 2014 % Change   2015 2014 % Change Operating revenue (1) 73,102 110,414 (33.8)   164,291 225,195 (27.0) Other revenue 108 67 61.2   383 113 238.9   73,210 110,481 (33.7)   164,674 225,308 (26.9) Operating costs (1) 35,082 75,732 (53.7)   83,088 146,704 (43.4) Operating income (1) 38,128 34,749 9.7   81,586 78,604 3.8 Operating income - net percentage (2) 52.1% 31.5%     49.5% 34.9%                   Land Drilling Rigs               Operating days (2) 2,202 4,441 (50.4)   4,897 8,752 (44.0) Drilling days (2) 1,938 3,851 (49.7)   4,204 7,578 (44.5) Rate per operating day (CDN$) (2) 33,184 22,890 45.0   33,188 23,747 39.8 Rate per operating day (US$) (2) 26,755 20,819 28.5   27,318 21,716 25.8 Utilization rate - operating day (2) 50% 80% (37.5)   55% 78% (29.5) Utilization rate - drilling day (2) 44% 70% (37.1)   47% 68% (30.9) Number of drilling rigs at period end 49 56 (12.5)   49 56 (12.5)                 Barge Drilling Rigs               Operating days (2) - 259 (100.0)   57 503 (88.7) Rate per operating day (CDN$) (2) - 37,953 (100.0)   29,972 37,886 (20.9) Rate per operating day (US$) (2) - 34,599 (100.0)   26,034 34,680 (24.9) Utilization rate - operating day (2) 0% 57% (100.0)   9% 56% (83.9) Number of barge drilling rigs at period end 2 2 -   2 2 - Number of barge drilling rigs under                 Bareboat Charter Agreements at period end  - 3 (100.0)   - 3 (100.0)

(1)	Operating revenue and operating costs for the three months ended June 30, 2015 and 2014 exclude third party recovery and third party costs of $3.7 million and $4.0 million, respectively. Operating revenue and operating costs for the six months ended June 30, 2015 and 2014 exclude third party recovery and third party costs of $4.9 million and $9.7 million, respectively.
(2)	See Non-GAAP Measures Definitions and Additional GAAP Measures Definitions section at the end of this document for further details.

In the second quarter and first half of 2015, Trinidad's US and international operations recorded increased operating income and higher dayrates compared to the same periods in 2014, despite soft market conditions. Oil and gas producers reduced capital spending in response to lower commodity prices, which resulted in lower activity across the Company's US land drilling and barge drilling operations. The impact of lower activity was largely offset by higher early termination and standby revenue received in the current periods.

Utilization for land rigs decreased to 50% and 55% in the three and six months ended June 30, 2015, respectively, compared to 80% and 78% for the same periods in the previous year as a result of slower demand and a higher number of rigs that received early termination and standby revenue with no associated operating days. Lower activity, partly offset by increased early termination and standby revenue, resulted in 33.8% and 27.0% lower operating revenue, respectively, in the three and six months ended June 30, 2015, compared to the same periods in 2014.

Trinidad's drilling contracts assisted in mitigating the effects of weakened industry conditions in the first half of 2015, as a number of customers chose to terminate contracts early due to reduced capital spending plans.  Revenue for the three and six months ended June 30, 2015 included US$11.8 million and US$27.9 million, respectively, of early termination and standby revenue for 14 rigs over the first half of 2015 (2014 - US$0.2 million and US$7.6 million, respectively).   The early termination and standby charges reflect the margins that would have been earned over the contract period for the respective rigs. Termination and standby revenue related to contracted periods after the period end are considered out-of-period early termination and standby revenue.  In the second quarter of 2015 and 2014, none of the early termination and standby revenue recognized was considered out-of-period.  On a year-to-date basis, $5.6 million of the early termination and standby revenue recognized was considered out-of-period, compared to $2.2 million in the same period last year. In addition, operating revenue was negatively impacted in 2015 by lower activity in the barge operations which were idle for a significant portion of the first half of 2015. These negative impacts on revenue were partly offset by the favorable impact of foreign exchange.

Dayrates in the three and six months ended June 30, 2015, for the US land drilling operations were, respectively US$5,936 and US$5,602 per day higher than in the same periods in 2014. Dayrates increased in the current periods as a result of higher early termination and standby revenue and a change in rig mix which led to a higher proportion of contracted and high specification rigs operating in the current year.  Excluding all early termination and standby revenue, dayrates increased by US$709 per day in the current quarter and US$813 per day year to date, compared to the same periods last year reflecting the higher specification rigs operating.

Operating income and operating income - net percentage in the second quarter and first half of 2015 increased from the levels recorded in the same periods in 2014.   Higher early termination and standby revenue combined with a stronger US dollar versus Canadian dollar had a positive impact on operating income and operating income - net percentage for the first half of 2015 compared to the prior year.  Cost savings initiated by management in the first half of 2015, including lower wages, reduced headcount and working with suppliers to lower costs where possible, has had a positive impact on the operating income and operating income - net percentage to date in 2015. The combination of higher specification rigs operating and a lowering cost structure led to higher operating income - net percentage in the current quarter and year to date, excluding the impact of early termination and standby revenue compared to the same periods last year.  In the second quarter of 2014, the Company also incurred costs of redeployment of Mexican rigs to Canada along with costs relating to reactivation of rigs within the division which did not occur in 2015.

At June 30, 2015, Trinidad's US and international rig count totaled 49 rigs, seven fewer rigs than at the same time last year and two more than at December 31, 2014. The reduction in rig count reflects the decommissioning of seven rigs in the second half of 2014 along with the redeployment of two US rigs. In the second quarter of 2015, the Company added two contracted new rig builds delivered by Trinidad's manufacturing division to the US and international division and also included the rig situated in the Middle East, which was purchased in the third quarter of 2014, in rig count as it is being marketed for use.  At the end of the second quarter, one rig was removed from rig count as it was classified as held for sale at June 30, 2015.  The sale is expected to be completed in the second half of 2015.

The barge drilling operations reflected the continuing softening of the barge market during the first half of 2015.  Dayrates and operating days were lower compared to the prior year with utilization at 9% for the first half of 2015.  As dayrates in the industry continued to lower and competition remained high for available drilling work, Trinidad chose to stack its five barge rigs during the first quarter of 2015.  The Company scaled back staffing levels and costs to reflect the current market and Trinidad did not extend the Bareboat Charter Agreements that expired at the end of the first quarter.  Negotiations on the redelivery of the three barge rigs are ongoing with the Company's counterpart.  The remaining two barge rigs owned by Trinidad remained stacked for the second quarter of 2015.

Second quarter of 2015 versus first quarter of 2015

Compared to the first quarter of 2015, revenue and operating income decreased by $18.3 million and $5.3 million, respectively, in the second quarter of 2015. Activity levels continued to decline as commodity prices remained weak and customer demand lowered in the second quarter of 2015.  Operating days for the land drilling operations were 493 days lower and utilization was 44% in the second quarter of 2015 compared to 51% in the first quarter of 2015.  In addition, revenue and operating income were lower as less early termination and standby revenue was recorded in the second quarter of 2015 compared to the first quarter of 2015.  The Company recorded US$16.1 million of early termination and standby revenue in the first quarter of 2015 compared to US$11.8 million in the second quarter of 2015.  Excluding all early termination and standby revenue in each quarter, land drilling dayrates were US$377 lower in the second quarter than in the first quarter of 2015.

As expected, the barge drilling operations negatively impacted the results of the second quarter of 2015 compared to the first quarter of 2015 as the Bareboat Charter Agreements expired, and were not renewed.  In the second quarter of 2015, Trinidad's remaining two barge rigs were stacked with no operating days or revenue recorded in the quarter.

Joint Venture Operations

Amounts are presented at 100% of the value included in the statement of operations and comprehensive income for Trinidad Drilling International (TDI); Trinidad owns 60% of the shares of TDI.

Three months ended June 30,   Six months ended June 30, ($ thousands except percentage and operating data) 2015 2014 (2) % Change   2015 2014 (2) % Change Operating revenue  32,086 10,137 216.5   58,099 13,453 331.9 Operating costs  17,125 5,248 226.3   32,594 7,322 345.2 Operating income (1) 14,961 4,889 206.0   25,505 6,131 316.0 Operating income - net percentage (1) 46.6% 48.2%     43.9% 45.6%                   Operating days (1)   516       926     Rate per operating day (CDN$) (1)   60,555       60,935     Rate per operating day (US$) (1)   48,959       49,785     Utilization rate - operating day (1)   95%       94%     Number of drilling rigs at period end 8 4 100.0   8 4 100.0 Number of active drilling rigs at period end 6 2 200.0   6 2 200.0

(1)	See Non-GAAP Measures Definitions and Additional GAAP Measures Definitions section at the end of this document for further details.
(2)	Operating data prior to the first quarter of 2015 has not been provided given the start-up nature of the operations.

TDI recorded a growing contribution in the second quarter and first half of 2015 as more rigs began earning revenue and operational costs were absorbed by expanding operations.

Operating income and operating income - net percentage for the three and six months ended June 30, 2015, respectively, were $15.0 million and $25.5 million and 46.6% and 43.9% reflecting the drilling, mobilization and standby activities for Mexico and drilling and mobilization activities for Saudi Arabia. Operating income increased significantly from the same periods last year, as a result of higher operating days, combined with additional mobilization and standby revenue.

In the second quarter, dayrates were positively impacted by two Mexican rigs receiving mobilization and standby revenue, with no associated operating days.

For the three and six months ended June 30, 2015, adjusted EBITDA from investment in joint venture was $6.7 million and $11.0 million, respectively, which were $5.8 million and $10.2 million, respectively, higher than the same periods of 2014, driven by higher activity.

TDI took ownership of the remaining two rigs for its Mexican operations in the first quarter of 2015, bringing the total rig count in the joint venture to eight. During the first half of 2015, TDI had all four rigs in Saudi Arabia and two rigs in Mexico drilling, with the other two Mexican rigs waiting on locations.

Manufacturing Operations

Three months ended June 30,   Six months ended June 30, ($ thousands except percentage) 2015 2014 % Change   2015 2014 % Change Operating revenue (1) 4,692 11,119 (57.8)   38,888 22,973 69.3 Other revenue 2 5 (60.0)   6 13 (53.8)   4,694 11,124 (57.8)   38,894 22,986 69.2 Operating costs (1) 4,473 9,952 (55.1)   36,009 20,788 73.2 Operating income (2) 221 1,172 (81.1)   2,885 2,198 31.3 Operating income - net percentage (2) 4.7% 10.5%     7.4% 9.6%

(1)

For the three months ended June 30, 2015, excluded from operating revenue and operating costs are downstream elimination entries of $2.4 million and $2.3 million, respectively (2014 - $9.1 million and $8.3 million, respectively). For the six months ended June 30, 2015, excluded from operating revenue and operating costs are downstream elimination entries of $51.4 million and $49.0 million, respectively (2014 - $16.8 million and $15.2 million, respectively). These entries remove Trinidad's percentage of profits related to manufacturing of rigs for the joint venture.

(2)

See Non-GAAP Measures Definitions and Additional GAAP Measures Definitions section at the end of this document for further details.

The purpose of the manufacturing operations is to support rig builds, rig maintenance and re-certifications for all of Trinidad's divisions, including all associates and joint ventures. Management does not commit to building a rig with the intention to earn significant profits on the rig build, and instead evaluates projects based on capital allocation and returns for the Company as a whole. All contracts are based on a cost-plus formula which is calculated in order for Trinidad to break even on rig builds when all costs, including general and administrative expenses, are factored in. Contracts are negotiated depending on the Company's varying involvement, which can range from full scale design and manufacturing to project management with a large degree of outsourcing.

For the three and six months ended June 30, 2015, Trinidad recognized revenue and expenses related to the rigs it was building for the Mexico joint venture operations and for the training rig it was building for Halliburton. Operating revenue increased in the first half of 2015 by $15.9 million or 69.3%, compared to the same period last year as external new build revenue or expenses were just beginning to be recognized in the first half of 2014, while 2015 included the completion of external projects noted above.  Operating revenue in the second quarter of 2015 was $6.4 million or 57.8% lower than the same period in 2014 reflecting the lower external activity in the current period with the external rig builds completed.

In 2015, Trinidad is constructing three new rig builds under long-term, take-or-pay contracts for its US operations. The rigs will be high performance Candrill, 1,500 horsepower, AC rigs with walking systems and 7,500 PSI circulating systems.  One of the rigs was completed at the end of the first quarter of 2015 with a second rig completed during the second quarter of 2015.  Work continues on the remaining rig which the Company expects to complete in the third quarter.

FINANCIAL HIGHLIGHTS - QUARTERLY ANALYSIS

2015  2014 2013 ($ millions except per share data and operating data)  Q2  Q1   Q4   Q3   Q2   Q1   Q4   Q3  Revenue 95.2 194.4 276.4 244.5 168.9 251.5 224.6 208.7 Operating income (1) 41.9 72.3 93.9 80.5 45.6 95.2 99.6 76.2 Operating income percentage (1) 44.0% 37.2% 34.0% 32.9% 27.0% 37.8% 44.4% 36.5% Operating income - net percentage (1) 46.3% 38.5% 35.6% 34.7% 28.3% 41.1% 47.0% 38.5% Net (loss) earnings (1.5) 12.1 (13.5) 19.2 (24.8) 25.9 28.8 9.2 Adjustments for:                   Depreciation and amortization  19.7 23.6 34.0 33.4 27.3 30.3 29.5 30.1   Foreign exchange  - 6.2 (0.1) 0.5 1.5 3.1 0.9 0.4   (Gain) loss on sale of property and equipment  (0.4) (1.1) 3.5 0.1 (1.3) (10.5) 0.1 (0.1)   Impairment of property and equipment  - - 56.9 - 20.6 - - -   (Gain) loss from investment in Joint Venture  (0.6) (1.2) (1.3) 1.6 (0.4) 0.1 0.8 -   Finance costs  12.9 11.4 9.8 9.7 10.0 10.0 12.0 10.4   Income taxes  (3.4) 4.4 (8.9) 4.9 (7.2) 15.3 11.1 5.9   Interest Income  - - - (0.1) (0.1) (0.2) (0.1) -   Other expense  1.4 2.9 0.6 (4.0) 5.3 5.5 1.5 5.9   Income taxes paid  (2.0) (1.6) (0.3) (0.7) (0.7) (0.5) (1.8) -   Income taxes recovered  0.1 0.2 0.4 1.3 0.2 0.3 1.5 0.4   Interest paid  (1.1) (20.8) (1.4) (19.5) (0.5) (18.7) (1.1) (18.4)   Interest received  - - - 0.1 0.1 0.2 0.1 - Funds provided by operations (1) 25.1 36.1 79.7 46.5 30.0 60.8 83.3 43.8 Net earnings (loss) per share (diluted) (0.01) 0.09 (0.10) 0.14 (0.18) 0.19 0.23 0.08 Funds provided by operations per share (diluted) (1) 0.19 0.27 0.58 0.34 0.22 0.44 0.67 0.36

(1)	See the Non-GAAP Measures Definitions and Additional GAAP Measures Definitions section at the end of this document for further details.

NON-GAAP MEASURES HIGHLIGHTS - QUARTERLY ANALYSIS

2015  2014 2013 ($ millions except per share data)  Q2  Q1   Q4   Q3   Q2   Q1   Q4   Q3  EBITDA (1) 27.7 51.5 21.3 67.2 5.4 81.3 81.2 55.6   Per share (diluted) (2) 0.21 0.39 0.15 0.48 0.04 0.58 0.65 0.46 Adjusted EBITDA (1) 34.7 60.0 77.3 64.6 30.6 79.4 83.8 61.8   Per share (diluted) (2) 0.26 0.45 0.56 0.47 0.22 0.57 0.68 0.51 Adjusted net (loss) earnings (1) (0.3) 18.0 23.6 14.6 (5.6) 27.7 31.2 15.4   Per share (diluted) (2) - 0.13 0.17 0.11 (0.04) 0.20 0.25 0.13

(1)	See the Non-GAAP Measures Definitions and Additional GAAP Measures Definitions section at the end of this document for further details.
(2)	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.

OPERATING HIGHLIGHTS - QUARTERLY ANALYSIS

			2015		2014				2013
			Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Land Drilling Market
Operating days (1)
	Canada		380	2,343	3,271	3,424	1,430	4,077	2,935	3,018
	United States and International		2,202	2,695	4,820	4,906	4,441	4,311	4,470	4,733
Rate per operating day (1)
	Canada (CDN$)		31,731	25,764	26,624	24,669	26,338	25,415	25,102	23,686
	United States and International (CDN$)		33,184	33,194	25,150	22,842	22,890	24,630	27,243	23,297
	United States and International (US$)		26,755	27,778	22,476	21,092	20,819	22,641	26,213	22,460
Utilization rate - operating day (1)
	Canada		8%	50%	62%	66%	26%	74%	52%	54%
	United States and International		50%	61%	97%	96%	80%	76%	71%	76%
Number of drilling rigs at period end (3)
	Canada		54	54	53	61	59	61	61	61
	United States and International		49	47	47	54	56	61	64	68
Barge Drilling Market
	Operating days (1)		-	57	212	334	259	244	394	449
	Rate per operating day (CDN$) (1)		-	29,993	36,616	37,967	37,953	37,815	34,810	33,962
	Rate per operating day (US$) (1)		-	26,051	32,795	35,072	34,599	34,767	33,490	32,740
	Utilization rate - operating day (1)		0%	13%	46%	73%	57%	54%	86%	97%
	Number of barge drilling rigs at period end		2	2	2	2	2	2	2	2
	Number of barge drilling rigs under
		Bareboat Charter Agreements at period end	-	3	3	3	3	3	3	3
Joint Venture Operations (2)
	Operating days (1)		516	410
	Rate per operating day (CDN$) (1)		60,555	61,412
	Rate per operating day (US$) (1)		48,959	50,825
	Utilization rate - operating day (1)		95%	94%
	Number of drilling rigs at period end		8	8	6	4	4	3	-	-

(1)	See Non-GAAP Measures Definitions and Additional GAAP Measures Definitions section at the end of this document for further details.
(2)	Trinidad is party to a joint venture with a wholly-owned subsidiary of Halliburton. The rigs are owned by the joint venture. Operating data prior to 2015 has not been provided given the start-up nature of the operations.
(3)	Refer to the Results from Operations section for details on changes to the rig count.

GENERAL AND ADMINISTRATIVE

Three months ended June 30,   Six months ended June 30, ($ thousands except percentage) 2015 2014 % Change   2015 2014 % Change General and administrative (1) 13,665 15,459 (11.6)   29,641 30,793 (3.7)   % of revenue  14.4% 9.2%     10.2% 7.3%     Share-based payment expense  1,302 3,756 (65.3)   1,729 9,331 (81.5)   Third party recoverable costs  233 369 (36.9)   800 651 22.9   Total general and administrative  15,200 19,584 (22.4)   32,170 40,775 (21.1)   % of revenue  16.0% 11.6%     11.1% 9.7%

(1)	General and administrative expenses excluding share-based payment expense and third party recoverable costs. This number is discussed as "Other G&A" per the below analysis.

For the three and six months ended June 30, 2015 total general and administrative (G&A) expenses decreased by 22.4% and 21.1%, respectively, when compared to the same periods in 2014.

For the three and six months ended June 30, 2015, other G&A expenses decreased by $1.8 million and $1.2 million, respectively, when compared to the prior year. Other G&A expenses decreased in 2015 as a result of cost reduction initiatives undertaken by Trinidad.  In each of the three and six month periods, office expenses, professional fees, travel and entertainment, and computer expenses decreased compared to the prior year partly offset by higher rent expense in 2015.  Administration salaries were lower in the second quarter compared to the prior year as the impact of headcount and salary reductions undertaken in the first quarter were more fully realized in the second quarter.  For the first half of the year, administration salaries are consistent with the prior year as costs associated with compensation packages provided as part of employee terminations were largely offset by salary reductions introduced during the quarter.  For the three and six months ended June 30, 2015, Trinidad recorded bad debt expense of $0.5 million, compared to $0.3 million for the three and six months ended June 30, 2014.

In light of the poor market conditions, Trinidad implemented several measures in the first quarter of 2015 to lower its G&A expenses. These measures included a headcount reduction, a 10% reduction in salaries and board fees for all executives and directors and a company-wide average wage rollback of 7% for salaried employees. Severance costs of approximately $1.8 million were included in the first quarter of 2015.  Excluding these one-time severance costs, other G&A expenses as a percentage of revenue for the six months ended June 30, 2015 would have been 9.6%.

Share-based payment expense decreased by $2.5 million and $7.6 million, respectively, in the three and six months ended June 30, 2015. The decrease in the current periods was mainly due to a significantly lower share price in 2015 partly offset by an increase in the number of Deferred Share Units and Performance Share Units outstanding during the current year.

Third party recoverable costs relate to costs incurred by Trinidad on behalf of the joint venture. As these costs are fully recoverable, Trinidad records a related revenue entry for this same amount, causing a nil net income effect.

FINANCIAL SUMMARY

As at		June 30,	December 31,
($ thousands)		2015	2014	$ Change
Working capital (1)		151,624	166,502	(14,878)
Senior Notes		559,849	519,759	40,090
Credit facility		69,925	15,000	54,925
		629,774	534,759	95,015
Less: unamortized debt issue costs		(6,324)	(6,951)	627
Total long-term debt		623,450	527,808	95,642
Total long-term debt as a percentage of assets		30.8%	27.2%
Total assets		2,024,223	1,941,621	82,602
Total long-term liabilities		738,737	628,047	110,690
Total long-term liabilities as a percentage of assets		36.5%	32.3%
Six months ended June 30,		2015	2014	$ Change
Cash provided by operations		114,549	90,519	24,030
Cash used by investing		(107,692)	(80,229)	(27,463)
Cash provided (used) by financing		32,935	(13,222)	46,157

(1)	See Non-GAAP Measures Definitions section at the end of this document for further details.

For the six months ended June 30, 2015, working capital decreased by $14.9 million when compared to December 31, 2014, due to a decrease in current assets of $87.9 million partly offset by a decrease in current liabilities of $73.0 million.

Current assets decreased in the year mainly due to a reduction in accounts receivable as a result of lower activity and strong collections during the year.  As well, costs included in inventory and prepaid expenses at December 31, 2014, relating to manufacturing of external rig builds were transferred to expense as Trinidad's manufacturing division completed work on the remaining external builds in the first quarter of the year.  Offsetting this was an increase in assets held for sale relating to a rig that is expected to be sold in the second half of 2015.

Current liabilities decreased in the current period mainly related to a decrease in accounts payable due to lower activity during the period for the land drilling operations in Canada and the US, combined with lower activity on external rig builds.  Deferred revenue lowered as the manufacturing division completed its external rig builds and recognized revenue for amounts collected in advance.

Trinidad's total long-term debt balance increased by $95.6 million compared to December 31, 2014. This increase was largely due to an increase in the Senior Notes at June 30, 2015, as a result of the increase in the US to Canadian dollar exchange rate at quarter end, as these notes are held in US funds. The Senior Notes are translated at each period end, as such their value fluctuates with exchange rates. The Senior Notes are due January 15, 2019 and interest is payable semi-annually in arrears on January 15 and July 15.  An additional $54.9 million was drawn on Trinidad's Canadian dollar revolving credit facility during the six months ended June 30, 2015, for a total of $69.9 million drawn on the facility at June 30, 2015.

The Company has available capacity of $130.1 million on its $200 Canadian revolving facility and all of the $200 million US revolving facility is available. In addition, Trinidad had $116.6 million in cash on hand at the end of the second quarter of 2015.

The Canadian and US revolving facilities require quarterly interest payments that are based on Bankers Acceptance and LIBOR rates and incorporate a tiered interest rate, which varies depending on the results of the Consolidated Total Debt to EBITDA ratio.

Capital Expenditures

Six months ended June 30,
($ thousands)	2015	2014
New builds	45,312	55,988
Capital upgrades and enhancements	12,341	24,397
Maintenance and infrastructure	6,317	22,408
Capital spares inventory	27,958	-
Total	91,928	102,793

 

During the six months ended June 30, 2015, a total of $91.9 million was spent on capital expenditures compared to $102.8 million in the prior year. These capital expenditures were substantially related to the Company's rig build program for its US operations as well as completing upgrades on existing equipment and capital inventory related to cancelled new builds and upgrades.

In addition to the amounts above, Trinidad spent $25.8 million related to its portion of capital spending for the joint venture in the first half of 2015. The joint venture took ownership of the remaining two rigs for its Mexican operations in the first quarter of 2015.

In 2015, Trinidad expects to spend a total of approximately $175.0 million on capital projects. This total includes the completion of three US new builds for Trinidad's fleet and two Mexican new builds for the joint venture, certain items purchased for new builds and upgrades that have been cancelled will be put into capital inventory for use in Trinidad's existing fleet.

2015 Capital Budget      ($ thousands)   2015 Growth capital (Trinidad owned equipment)   90,000 Capital inventory   35,000 Maintenance and infrastructure capital   10,000     135,000 Joint venture capital (Trinidad's 60% share)   40,000 Total 2015 capital budget   175,000

Trinidad expects cash provided by operations and the Company's various sources of financing to be sufficient to meet its debt repayments, future obligations and to fund planned capital expenditures.

Current financial performance is within the financial ratio covenants under the revolving credit facility as reflected in the table below:

RATIO		June 30,	December 31,		THRESHOLD
		2015	2014
Consolidated Senior Debt to Consolidated Bank EBITDA (1)		(0.16):1	(0.18):1		3.00:1 maximum
Consolidated Total Debt to Consolidated Bank EBITDA (1)		2.36:1	1.93:1		4.00:1 maximum
Consolidated Bank EBITDA to Consolidated Cash Interest Expense (1)		5.08:1	6.20:1		2.75:1 minimum

(1)	Please see the Non-GAAP Measures Definitions section at the end of this document for further details.

At June 30, 2015, Total Debt to Bank EBITDA was 2.36 times, compared to 1.93 times at December 31, 2014. Total Debt to Bank EBITDA increased due to lower adjusted EBITDA for the first half of 2015 compared to the prior year and a higher debt balance at June 30, 2015, resulting from a stronger US dollar translation and draws on the credit facility.

Note that Consolidated Bank EBITDA does not include EBITDA from investment in joint venture.  Dividends paid to Trinidad from the joint venture would be eligible for inclusion in Consolidated Bank EBITDA in the period that payment occurs. At June 30, 2015, the cumulative adjusted EBITDA from investment in joint venture was $11.8 million, of which no amounts have been paid back by the joint venture.  The joint venture had $17.8 million of cash on its statement of financial position at June 30, 2015. Given the start-up nature of the operations, no payments of cumulative adjusted EBITDA from investment in joint venture have been made.  If the unpaid cumulative adjusted EBITDA from joint venture was included at June 30, 2015, the Total Debt to Bank EBITDA would be 2.21:1.

Readers are cautioned that the ratios noted above do not have standardized meanings as calculated under IFRS.

OUTLOOK

Following a slower-than-typical spring break-up, activity levels and the level of customer enquiries in Canada have increased. In the US, a more stabilized active rig count and opportunities to high grade existing active rigs provide positive initial signs that industry conditions are at, or near, bottom. Despite the positive indicators, competition for work remains high and dayrates have not yet shown significant signs of improvement. Typically, dayrates increase after one or two quarters of higher utilization levels.

Over the past six months, the oil and gas industry as a whole has worked to lower its cost structure and become more efficient. These changes have improved the economics of certain oil and gas resources and allow development to proceed at lower commodity prices than before. Trinidad believes that these changes, along with stability or improvement in commodity prices, will allow activity levels to gradually increase throughout the remainder of 2015, with further improvement in industry conditions more likely in 2016.

The relative stability and slight improvement in crude oil prices witnessed in the second quarter of 2015 was interrupted early in the third quarter. A pullback in oil prices in July was largely driven by the potential removal of sanctions against Iran, allowing incremental crude oil supply to enter the global market. In addition, economic instability in Greece and China negatively impacted oil prices. While it is too early to know if this price reduction will persist, the return of volatility to commodity prices increases uncertainty and may delay or slow a rebound in the drilling sector.

Trinidad's contracts have helped to mitigate some of the weakness in industry conditions to date in 2015. The long-term, take-or-pay contracts have provided a level of stability and lump sum payments to offset lower activity levels on the remainder of the fleet. Trinidad currently has more than 40% of its fleet under long-term contracts with an average term remaining of approximately 1.5 years.

Trinidad has one rig currently under construction. This rig is under a long-term, take-or-pay contract and is expected to be delivered in to the Company's US operations in the third quarter of 2015. In addition, Trinidad continues to evaluate opportunities to move existing idle rigs into international locations, either through its international joint venture or independently.

At the end of the second quarter, Trinidad had $70 million drawn on its credit facility, with $130 million remaining available on its Canadian credit facility and US$200 million available on its US credit facility. In addition, Trinidad had $116 million in cash on hand at the end of the second quarter of 2015. Under current conditions, Trinidad does not foresee any liquidity issues over the remainder of 2015.

In June of 2015, Trinidad announced a strategic business combination with CanElson. Information regarding the transaction has been mailed to shareholders of both companies, with shareholder meetings planned for August 10, 2015. Pending shareholder and regulatory approvals, the transaction is expected to close prior to the end of August 2015.

Combining CanElson's operations with Trinidad's creates a larger, more diverse fleet that is able to meet the varied needs of customers. It expands Trinidad's customer base, lowers corporate leverage and provides an increased cash flow base to take advantage of growth opportunities. In addition, three CanElson board members will be joining the Trinidad Board of Directors and the majority of CanElson's executive team will also be joining Trinidad, providing diverse management skills and additional guidance. In current weaker market conditions, the addition of CanElson's fleet provides additional opportunities to redeploy existing assets to international markets, generates incremental cash flow for the Company and provides lower leverage. Once better conditions return, Trinidad believes that the combined company with its highly marketable and highly utilized fleet will be even better positioned to take advantage of opportunities presented with the rebound in the market.

CONFERENCE CALL

Conference Call:	Wednesday, August 5th, 2015 beginning at 9:00 a.m. MT (11:00 a.m. ET).
	888-231-8191 (toll-free in North America) or 647-427-7450 approximately 10 minutes prior to the conference call.
Archived Recording:	Available from approximately 12:30 p.m. MT on August 5th, 2015 until midnight August 15th, 2015.  The dial-in number is 855-859-2056 or 416-849-0833 and access code is 54830251.
Webcast:	Available at https://www.trinidaddrilling.com/investors/events-presentations

TRINIDAD DRILLING LTD.
Trinidad is a corporation focused on sustainable growth that trades on the Toronto Stock Exchange under the symbol TDG. Trinidad's divisions operate in the drilling and barge-drilling sectors of the North American oil and natural gas industry with operations in Canada and the United States. In addition, through a joint venture, Trinidad has the opportunity to operate drilling rigs in other international markets such as Saudi Arabia and Mexico. Trinidad is focused on providing modern, reliable, expertly designed equipment operated by well-trained and experienced personnel. Trinidad's drilling fleet is one of the most adaptable, technologically advanced and competitive in the industry.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
As at	June 30,	December 31,
($ thousands) - unaudited	2015	2014
Assets
Current Assets
Cash and cash equivalents	115,569	71,062
Accounts receivable	108,251	223,750
Inventory	13,963	29,618
Prepaid expenses	5,195	19,755
Asset held for sale	13,293	-
	256,271	344,185
Property and equipment	1,403,922	1,325,730
Intangible assets and goodwill	107,577	99,678
Deferred income taxes	29,674	8,070
Investment in joint venture	226,779	163,958
	2,024,223	1,941,621
Liabilities
Current Liabilities
Accounts payable and accrued liabilities	94,017	156,003
Dividends payable	6,671	6,758
Deferred revenue and customer deposits	3,959	14,922
	104,647	177,683
Long-term debt	623,450	527,808
Deferred income taxes	115,287	100,239
	843,384	805,730
Shareholders' Equity
Common shares	1,079,411	1,093,426
Contributed surplus	64,758	59,005
Accumulated other comprehensive income	118,360	62,470
Deficit	(81,690)	(79,010)
	1,180,839	1,135,891
	2,024,223	1,941,621

 

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME AND LOSS
		Three months ended		Six months ended
		June 30,		June 30,
($ thousands) - unaudited		2015	2014	2015	2014
Revenue
Oilfield service revenue		94,842	168,146	288,345	418,593
Other revenue		371	799	1,264	1,857
		95,213	168,945	289,609	420,450
Expenses
Operating expense		53,317	123,340	175,431	279,653
General and administrative		15,200	19,584	32,170	40,775
Depreciation and amortization		19,693	27,430	43,305	57,685
Foreign exchange		40	1,635	6,199	4,789
Gain on sale of property and equipment		(384)	(1,270)	(1,484)	(11,809)
Impairment of property and equipment		-	20,630	-	20,630
		87,866	191,349	255,621	391,723
Gain from investment in joint venture		(646)	(419)	(1,917)	(288)
Finance and transaction costs		12,894	10,049	24,320	20,008
(Loss) earnings before income taxes		(4,901)	(32,034)	11,585	9,007
Income taxes
Current		591	3,605	3,237	3,895
Deferred		(4,025)	(10,824)	(2,315)	4,165
		(3,434)	(7,219)	922	8,060
Net (loss) income		(1,467)	(24,815)	10,663	947
Other comprehensive income
Foreign currency translation adjustment,
	net of income tax	(8,688)	(23,587)	55,890	1,256
		(8,688)	(23,587)	55,890	1,256
Total comprehensive (loss) income		(10,155)	(48,402)	66,553	2,203
Earnings per share
Net (loss) income
	Basic / Diluted	(0.01)	(0.18)	0.08	0.01

 

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For six months ended June 30, 2015 and 2014			Accumulated
			other
	Common	Contributed	comprehensive		Total
($ thousands) - unaudited	shares	surplus	income (1)	(Deficit)	equity
Balance at December 31, 2014	1,093,426	59,005	62,470	(79,010)	1,135,891
Shares repurchased through normal course issuer bid	(14,015)	5,665	-	-	(8,350)
Share-based payment expense	-	88	-	-	88
Total comprehensive income	-	-	55,890	10,663	66,553
Dividends	-	-	-	(13,343)	(13,343)
Balance at June 30, 2015	1,079,411	64,758	118,360	(81,690)	1,180,839
Balance at December 31, 2013	1,117,197	50,607	4,404	(58,120)	1,114,088
Exercise of stock options	807	(215)	-	-	592
Share-based payment expense	-	301	-	-	301
Total comprehensive income	-	-	1,256	947	2,203
Dividends	-	-	-	(13,818)	(13,818)
Balance at June 30, 2014	1,118,004	50,693	5,660	(70,991)	1,103,366

(1)	Accumulated other comprehensive income consists of the foreign currency translation adjustment.
	All amounts will be reclassified to profit or loss when specific conditions are met.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS
For six months ended June 30,
($ thousands) - unaudited				2015			2014
Cash provided by (used in)
Operating activities
Net earnings				10,663			947
Adjustments for:
	Depreciation and amortization			43,305			57,685
	Foreign exchange			6,199			4,789
	Gain on sale of property and equipment			(1,484)			(11,809)
	Impairment of property and equipment			-			20,630
	Gain from investment in joint venture			(1,917)			(288)
	Finance costs			24,320			20,008
	Income taxes			922			8,060
	Interest income			(27)			(326)
	Other (1)			4,333			10,854
	Income taxes paid			(3,618)			(1,105)
	Income taxes recovered			286			490
	Interest paid			(21,785)			(19,119)
	Interest received			27			326
Funds provided by operations				61,224			91,142
Change in non-cash operating working capital				53,325			(623)
Cash provided by operations				114,549			90,519
Investing activities
Purchase of property and equipment				(91,928)			(102,793)
Proceeds from disposition of property and equipment				3,987			128,782
Investment in joint venture				(48,162)			(119,691)
Purchase of intangibles				(810)			-
Change in non-cash working capital				29,221			13,473
Cash used by investing				(107,692)			(80,229)
Financing activities
Proceeds from long-term debt				54,925			-
Repurchase of shares				(8,350)			-
Proceeds from exercise of options				-			592
Dividends paid				(13,429)			(13,814)
Finance costs				(211)			-
Cash (used) provided by financing				32,935			(13,222)
Cash flow from operating, investing and financing activities				39,792			(2,932)
Effect of translation of foreign currency cash				4,715			(1,276)
Increase (decrease) in cash for the period				44,507			(4,208)
Cash and cash equivalents - beginning of period				71,062			268,160
Cash and cash equivalents - end of period				115,569			263,952

(1)	Other includes share-based payment expense and elimination of downstream transactions in the Manufacturing Operations net earnings.

SEGMENTED INFORMATION

The following presents the result of Trinidad's operating segments:

For three months ended						United States /
June 30, 2015			Canadian			International			Manufacturing			Joint Venture			Inter-segment
($ thousands)			Operations			Operations			Operations			Operations (1)			Eliminations			Corporate			Total
Operating revenue			12,061			73,102			7,074			-			-			-			92,237
Other revenue			28			183			2			-			-			-			213
Third party recovery			1,310			3,677			-			-			-			-			4,987
General and administrative - third party recovery			-			-			-			-			-			233			233
Inter-segment revenue			-			-			30,254			-			(30,254)			-			-
Elimination of downstream transactions			-			(75)			(2,382)			-			-			-			(2,457)
			13,399			76,887			34,948			-			(30,254)			233			95,213
Operating costs			8,775			35,082			6,782			-			-			-			50,639
Third party costs			1,310			3,677			-			-			-			-			4,987
Inter-segment operating			-			-			30,254			-			(30,254)			-			-
Elimination of downstream transactions			-			-			(2,309)			-			-			-			(2,309)
Operating income			3,314			38,128			221			-			-			233			41,896
Depreciation and amortization			6,241			12,862			590			-			-			-			19,693
Loss (gain) on sale of assets			1,156			(1,041)			(499)			-			-			-			(384)
			7,397			11,821			91			-			-			-			19,309
Segmented (loss) income			(4,083)			26,307			130			-			-			233			22,587
Gain from investment in joint venture			-			-			-			(646)			-			-			(646)
General and administrative			-			-			-			-			-			14,967			14,967
General and administrative - third party costs			-			-			-			-			-			233			233
Foreign exchange			-			-			-			-			-			40			40
Finance costs			-			-			-			-			-			12,894			12,894
Income taxes			-			-			-			-			-			(3,434)			(3,434)
Net (loss) earnings			(4,083)			26,307			130			646			-			(24,476)			(1,467)
Purchase of property and equipment			4,678			37,097			18			-			-			-			41,793

(1)	The gain from investment in joint venture reflects the Company's share of the financial performance of TDI during the period. The Company's share of individual assets and liabilities are recognized as an investment on the consolidated statements of financial position.

For three months ended            United States /                               June 30, 2014     Canadian     International     Manufacturing     Joint Venture     Inter-segment             ($ thousands)     Operations     Operations     Operations     Operations (1)     Eliminations     Corporate     Total                                             Operating revenue      37,681     110,414     20,248     -     -     -     168,343 Other revenue      358     67     5     -     -     -     430 Third party recovery      4,930     4,002     -     -     -     -     8,932 General and administrative - third party recovery      -     -     -     -     -     369     369 Inter-segment revenue      -     -     11,759     -     (11,759)     -     - Elimination of downstream transactions      -     -     (9,129)     -     -     -     (9,129)       42,969     114,483     22,883     -     (11,759)     369     168,945 Operating costs      28,724     75,732     18,252     -     -     -     122,708 Third party costs      4,930     4,002     -     -     -     -     8,932 Inter-segment operating      -     -     11,759     -     (11,759)     -     - Elimination of downstream transactions      -     -     (8,300)     -     -     -     (8,300) Operating income      9,315     34,749     1,172     -     -     369     45,605 Depreciation and amortization      8,101     18,947     382     -     -     -     27,430 Loss (gain) on sale of assets      55     (4,073)     -     -     -     -     (4,018) Elimination of downstream transactions      -     2,748     -     -     -     -     2,748 Impairment of capital assets      13,367     7,263     -     -     -     -     20,630       21,523     24,885     382     -     -     -     46,790 Segmented (loss) income      (12,208)     9,864     790     -     -     369     (1,185) Gain from investment in joint venture      -     -     -     (419)     -     -     (419) General and administrative      -     -     -     -     -     19,215     19,215 General and administrative - third party costs      -     -     -     -     -     369     369 Foreign exchange      -     -     -     -     -     1,635     1,635 Finance costs      -     -     -     -     -     10,049     10,049 Income taxes      -     -     -     -     -     (7,219)     (7,219) Net (loss) earnings     (12,208)     9,864     790     419     -     (23,680)     (24,815) Purchase of property and equipment      19,992     51,496     100     -     -     -     71,588

(1)	The gain from investment in joint venture reflects the Company's share of the financial performance of TDI during the period. The Company's share of individual assets and liabilities are recognized as an investment on the consolidated statements of financial position.

For six months ended						United States /
June 30, 2015			Canadian			International			Manufacturing			Joint Venture			Inter-segment
($ thousands)			Operations			Operations			Operations			Operations (1)			Eliminations			Corporate			Total
Operating revenue			72,431			164,291			90,326			-			-			-			327,048
Other revenue			73			520			6			-			-			-			599
Third party recovery			7,861			4,876			-			-			-			-			12,737
General and administrative - third party recovery			-			-			-			-			-			800			800
Inter-segment revenue			-			-			71,656			-			(71,656)			-			-
Elimination of downstream transactions			-			(137)			(51,438)			-			-			-			(51,575)
			80,365			169,550			110,550			-			(71,656)			800			289,609
Operating costs			43,597			83,088			84,980			-			-			-			211,665
Third party costs			7,861			4,876			-			-			-			-			12,737
Inter-segment operating			-			-			71,656			-			(71,656)			-			-
Elimination of downstream transactions			-			-			(48,971)			-			-			-			(48,971)
Operating income			28,907			81,586			2,885			-			-			800			114,178
Depreciation and amortization			15,372			26,756			1,177			-			-			-			43,305
Loss (gain) on sale of assets			1,198			(2,183)			(499)			-			-			-			(1,484)
			16,570			24,573			678			-			-			-			41,821
Segmented income			12,337			57,013			2,207			-			-			800			72,357
Gain from investment in joint venture			-			-			-			(1,917)			-			-			(1,917)
General and administrative			-			-			-			-			-			31,370			31,370
General and administrative - third party costs			-			-			-			-			-			800			800
Foreign exchange			-			-			-			-			-			6,199			6,199
Finance costs			-			-			-			-			-			24,320			24,320
Income taxes			-			-			-			-			-			922			922
Net earnings (loss)			12,337			57,013			2,207			1,917			-			(62,811)			10,663
Purchase of property and equipment			19,401			72,319			208			-			-			-			91,928

(1)	The gain from investment in joint venture reflects the Company's share of the financial performance of TDI during the period. The Company's share of individual assets and liabilities are recognized as an investment on the consolidated statements of financial position.

For six months ended           United States /                               June 30, 2014     Canadian     International     Manufacturing     Joint Venture     Inter-segment             ($ thousands)     Operations     Operations     Operations     Operations (1)     Eliminations     Corporate     Total                                             Operating revenue     141,288     225,195     39,726     -     -     -     406,209 Other revenue     1,080     113     13     -     -     -     1,206 Third party recovery     19,452     9,685     -     -     -     -     29,137 General and administrative - third party recovery     -     -     -     -     -     651     651 Inter-segment revenue     -     -     21,672     -     (21,672)     -     - Elimination of downstream transactions     -     -     (16,753)     -     -     -     (16,753)       161,820     234,993     44,658     -     (21,672)     651     420,450 Operating costs     83,024     146,704     36,018     -     -     -     265,746 Third party costs     19,452     9,685     -     -     -     -     29,137 Inter-segment operating     -     -     21,672     -     (21,672)     -     - Elimination of downstream transactions     -     -     (15,230)     -     -     -     (15,230) Operating income     59,344     78,604     2,198     -     -     651     140,797 Depreciation and amortization     19,961     36,927     797     -     -     -     57,685 Loss (gain) on sale of assets     (206)     (29,729)     -     -     -     -     (29,935) Elimination of downstream transactions     -     18,126     -     -     -     -     18,126 Impairment of capital assets     13,367     7,263     -     -     -     -     20,630       33,122     32,587     797     -     -     -     66,506 Segmented income     26,222     46,017     1,401     -     -     651     74,291 Gain from investment in joint venture     -     -     -     (288)     -     -     (288) General and administrative     -     -     -     -     -     40,124     40,124 General and administrative - third party costs     -     -     -     -     -     651     651 Foreign exchange     -     -     -     -     -     4,789     4,789 Finance costs     -     -     -     -     -     20,008     20,008 Income taxes     -     -     -     -     -     8,060     8,060 Net earnings (loss)     26,222     46,017     1,401     288     -     (72,981)     947                                             Purchase of property and equipment     33,029     69,601     163     -     -     -     102,793

(1)	The gain from investment in joint venture reflects the Company's share of the financial performance of TDI during the period. The Company's share of individual assets and liabilities are recognized as an investment on the consolidated statements of financial position.

ADVISORY

NON-GAAP MEASURES DEFINITIONS

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 EBITDA, EBITDA from investment in joint venture, Adjusted EBITDA, Adjusted net (loss) earnings, working capital, Senior Debt to Bank EBITDA, Total Debt to Bank EBITDA, Bank EBITDA to Cash Interest Expense, drilling days, operating days, utilization rate - drilling day, utilization rate - operating day, and rate per operating day or dayrate.  These non-GAAP measures are identified and defined as follows:

"EBITDA" is a measure of the Company's operating profitability. 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 and amortized or how the results are taxed in various jurisdictions.

EBITDA is derived from the consolidated statements of operations and comprehensive income and is calculated as follows:

		Three months ended June 30,		Six months ended June 30,
($ thousands)		2015	2014	2015	2014
Net (loss) earnings		(1,467)	(24,815)	10,663	947
Plus:
	Finance costs	12,894	10,049	24,320	20,008
	Depreciation and amortization	19,693	27,430	43,305	57,685
	Income taxes	(3,434)	(7,219)	922	8,060
EBITDA		27,686	5,445	79,210	86,700

 

"EBITDA from investment in joint venture" provides an indication of the results generated by the Company's joint venture operations prior to how these activities are financed, assets are depreciated and amortized or how the results are taxed in various jurisdictions.

EBITDA from investment in joint venture is derived from the consolidated statements of operations and comprehensive income of Trinidad Drilling International (TDI) and is calculated as follows:

		Three months ended June 30,		Six months ended June 30,
($ thousands)		2015	2014	2015	2014
Gain from investment in joint venture		646	419	1,917	288
Plus:
	Finance costs	122	-	220	-
	Depreciation and amortization	4,444	342	6,860	342
	Income taxes	1,249	106	1,555	107
EBITDA from investment in joint venture		6,461	867	10,552	737

 

"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 (gain) loss from investment in joint venture and including Adjusted EBITDA from investment in joint venture. Adjusted EBITDA is not intended to represent net earnings (loss) 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 expense.

Adjusted EBITDA is calculated as follows:

		Three months ended June 30,		Six months ended June 30,
($ thousands)		2015	2014	2015	2014
EBITDA		27,686	5,445	79,210	86,700
Plus:
	Gain on sale of property and equipment	(384)	(1,270)	(1,484)	(11,809)
	Impairment of property and equipment	-	20,630	-	20,630
	Share-based payment expense	1,302	3,756	1,729	9,331
	Foreign exchange	40	1,635	6,199	4,789
	Gain from investment in joint venture	(646)	(419)	(1,917)	(288)
Plus:
	Adjusted EBITDA from investment in joint venture	6,681	867	10,971	733
Adjusted EBITDA		34,679	30,644	94,708	110,086

 

"Adjusted EBITDA from investment in joint venture" is used by management and investors to analyze EBITDA (as defined above) prior to the effect of foreign exchange, share-based payment expense, impairment expense and the sale of assets. Adjusted EBITDA from investment in joint venture is not intended to represent net (loss) earnings as calculated in accordance with IFRS. Adjusted EBITDA from investment in joint venture provides an indication of the results generated by TDI'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 expense.

Adjusted EBITDA from investment in joint venture is calculated as follows:

		Three months ended June 30,		Six months ended June 30,
($ thousands)		2015	2014	2015	2014
EBITDA from investment in joint venture		6,461	867	10,552	737
Plus:
	Foreign exchange	220	-	419	(4)
Adjusted EBITDA from investment in joint venture		6,681	867	10,971	733

 

"Adjusted net earnings" is used by management and the investment community to analyze net earnings prior to the effect of foreign exchange, share-based payment expense, any gains or losses on the sale of assets in the period and impairment charges, including taking into account the tax effects of these items. This measure is not intended to represent net earnings as calculated in accordance with IFRS. Adjusted net earnings is a useful measure because it provides an indication of results of the Company's principal business activities before consideration of fluctuations in foreign exchange gains and losses, impairment and share-based payment expenses, which are not consistently incurred period over period.

"Working capital" is used by management and the investment community to analyze the operating liquidity available to the Company.

"Senior Debt to Bank EBITDA" is defined as the consolidated balance of the revolving facility and other debt secured by a lien at quarter end to consolidated Bank EBITDA for the trailing 12 months (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.

"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 less unrestricted cash in excess of $10.0 million, 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.

Total Debt to Bank EBITDA is calculated as follows:

As At				June 30,	December 31,
($ thousands)				2015	2014
Total Debt:
	Senior notes, principal (US$450.0 million)			562,050	522,045
	Draw on credit facility			70,000	15,000
	Dividends payable			6,671	6,758
	Letters of credit			81	75
	Cash in excess of $10.0 million			(105,569)	(61,062)
				533,233	482,816
Bank EBITDA (TTM):
	Net earnings			16,312	6,596
	Income taxes			(3,062)	4,076
	Financing costs			43,843	39,531
	Depreciation and amortization			110,632	125,012
	Impairment			56,905	77,535
	(Gain) loss from investment in joint venture			(1,648)	(19)
	(Gain) loss on sale of property and equipment			2,087	(8,238)
	Unrealized foreign exchange			7,907	4,580
	Share-based payment expense			(6,837)	765
				226,139	249,838
Total Debt to Bank EBITDA				2.36	1.93

 

"Bank EBITDA to Cash Interest Expense" is defined as the consolidated Bank EBITDA for TTM to the cash interest expense on all debt balances for 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 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).

ADDITIONAL 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, Operating income percentage and Operating income - net percentage. 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 (loss) 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 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 percentage" is used by management and investors to analyze overall and segmented operating performance, including third party recovery and third party costs, as well as inter-segment revenue and inter-segment operating costs. Operating income percentage is calculated from the consolidated statements of operations and comprehensive income and from the segmented information in the notes to the consolidated financial statements. Operating income percentage is defined as operating income divided by revenue.

"Operating income - net percentage" 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 revenue and expenses do not have an effect on consolidated net (loss) earnings. Operating income - net percentage is calculated from the consolidated statements of operations and comprehensive income 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.

FORWARD-LOOKING STATEMENTS

This document contains certain forward-looking statements relating to Trinidad's plans, strategies, objectives, expectations and intentions. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "confident", "might" and similar expressions are intended to identify forward-looking information or statements. Various assumptions were used in drawing the conclusions or making the projections contained in the forward-looking statements throughout this document. The forward-looking information and statements included in this document are not guarantees of future performance and should not be unduly relied upon. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated and described in the forward-looking statements. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements. In particular, but without limiting the foregoing, this document may contain forward-looking information and statements pertaining to the completion of announced rig construction programs on a timely basis and economical terms; the assumption that Trinidad's customers will honour their take-or-pay contracts; fluctuations in the demand for Trinidad's services; the ability for Trinidad to attract and retain qualified personnel, in particular field staff to crew the Company's rigs; the existence of competitors, technological changes and developments in the oilfield services industry; the existence of operating risks inherent in the oilfield services industry; assumptions respecting capital expenditure programs and other expenditures by oil and gas exploration and production companies; assumptions regarding commodity prices, in particular oil and natural gas; assumptions respecting supply and demand for commodities, in particular oil and natural gas; assumptions regarding foreign currency exchange rates and interest rates; the existence of regulatory and legislative uncertainties; the possibility of changes in tax laws; and general economic conditions including the capital and credit markets; assumptions made about future performance and operations of the joint venture arrangement; assumptions made about the proposed business combination with CanElson. Trinidad cautions that the foregoing list of assumptions, risks and uncertainties is not exhaustive. Additional information on these and other factors that could affect Trinidad's business, operations or financial results are described in reports filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com) including but not limited to Trinidad's annual document, financial statements, Annual Information Form and Trinidad and CanElson's Joint Management Information Circular. The forward-looking information and statements contained in this document speak only as of the date of this document and Trinidad assumes no obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable securities laws.

SOURCE Trinidad Drilling Ltd.

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