Unassociated Document

The following responses address the comments of the reviewing Staff of the United States Securities and Exchange Commission as set forth in a letter dated January 29, 2010 (the “Comment Letter”) relating to the financial statements and related disclosures in the annual report on Form 10-K for the fiscal year-ended January 31, 2009 and the quarterly report on Form 10-Q for the Quarter ended October 31, 2009. The answers set forth herein refer to the Staffs' comments.

1.	We note your disclosure stated “oil and gas operations are generally conducted jointly with others….” Please disclose how you account for your “gas-balancing” arrangements to comply with EITF 90-22.

The Company’s operating agreements with its partners do not permit the partners to take more than its working interest gas production. If gas balancing situations do arise the Company anticipates applying the “sales method”. This will be disclosed in future filings. The amount of imbalance in terms of units and value is not significant.

We note your disclosures regarding the circumstances under which proved and unproved properties were either sold or “considered impaired” resulting in either gains or losses in your statements of operations. Given that you elected to apply the full cost method, gains or losses on sales or abandonments should be accounted for as adjustments to amounts capitalized for the respective cost centers unless you satisfy the criteria outlined in Rule 4-10(c)(6)(i) of Regulation S-X.

Further, since the term “impairment” is utilized in the full cost rules to refer to an assessment of unproved properties that results in these costs being added to the costs of properties subject to amortization, as stated in Rule 4-10(c)(3)(ii)(A), it is important to distinguish between impairments and ceiling test write-downs.

Any disclosures stating that you recorded impairment charges after determining that certain properties “exceeded their estimated realizable value,” should be modified to clarify whether you are actually referring to ceiling test write-downs. If so, please also tell us how your computations are consistent with the ceiling test prescribed in Rule 4-10(c)(4) of Regulation S-X. If the amounts you recorded as impairment charges were not the result of a ceiling test, please quantify the differences and tell us how you propose to properly account for these items.

On a related point, your description of the ceiling test within your “Oil and Gas Properties” accounting policy note at page F-8, stating that the ceiling includes the lower of cost or estimated fair value of the unproven properties “not included in the costs being amortized” is incorrect and should be modified to eliminate the negative to comply with Rule 4-10(c)(4)(C) of Regulation S-X.

Please submit the accounting and disclosure revisions that you propose to resolve the concerns over your recognition of the various gains, losses and impairments described. If you believe your accounting is consistent with this guidance, please submit details sufficient to understand how you arrived at this view.

We agree that the Form 10-K was not clear as to impairments versus ceiling test write-downs. The carrying amount of petroleum and natural gas properties in our Canadian and U.S. cost centers is substantially comprised of unproven properties and each of the Canadian and U.S. cost centers had limited net book value and limited ceiling test limits (net present value of proven reserves discounted at 10% approximated the carrying amount). Therefore, the distinction between impairments of unproved properties that are transferred to the full cost pool and then expensed through ceiling test write-downs does not significantly impact the financial statements. In addition, this distinction had no impact on the reported results of Triangle. However, we will ensure that this distinction is clarified in future filings.

In Canada, our full costs pool was reduced to its ceiling test limit before impairments of the unproved properties. Thus, as impairments in the unproven properties were recognized, ceiling test write-downs were triggered. The mechanics of the calculations were:

In the U.S., sales of proved properties in 2008 from the U.S. full cost pool reduced the full cost pool to nil (i.e. a gain was recorded on the sales since the proved properties were sold for more than the carrying value of the pool). Furthermore, the remaining assets in the proved properties pool had been reduced to their ceiling test limit during the second and third quarters of fiscal 2009 since, under Rule 4-10(4)(A), the net present value of the proved reserves was negative. Thus, as impairments in the unproven properties were recognized, an automatic ceiling test write-down was triggered.

To clarify the differences between impairments in unproven properties and ceiling test impairments in our fiscal year ended January 31, 2010 Form 10-K, we propose the disclosures in Note 4 of the financial statements will be amended as follows:

·	the Company’s proved properties in Alberta exceeded their estimated realizable value the ceiling test limit as described in Note 2(f), which resulted in a $178,452 non-cash impairment loss ceiling test write-down being recognized; and

the Company sold its interests in a Barnett shale well in June 2008 for gross proceeds of $164,985. The net book value of the US proved property costs full costs pools at the time of the sale was $131,820$161,825 and the related properties had an asset retirement obligation of $7,545. As such, the Company recorded a gain on the sale of assets of $40,710$10,705.

·	the Company’s proved properties in Alberta exceeded their estimated realizable value the ceiling test limit as described in Note 2(f), which resulted in a $6,939,006 non-cash impairment loss ceiling test write-down being recognized;

·	the Company’s proved properties in Texas exceeded their estimated realizable value the ceiling test limit as described in Note 2(f), which resulted in a $3,082,346 non-cash impairment loss ceiling test write-down being recognized; and

·	the Company sold its 27% interest in 12,100 gross acres in northeast Hill County of Texas for gross proceeds of $983,902 (proven land and geological and geophysical costs of $1,929,305), which resulted in a $945,403 non-cash impairment ceiling test write-down being recognized.

·	In Canada, $16,869,995 (2008 - $15,463,119) of unproven property costs were excluded from costs subject to depletion, which relate to Canadian shale gas exploration costs mainly in the Windsor Block of the Maritimes Basin.

·	The Company anticipates that these costs will be subject to depletion in fiscal 2011, when the Company anticipates having pipelines built and commissioned to market potential gas from the Windsor Block (note: this information will be updated when future filings are prepared).

In December 2008, the Company elected to not drill a test well on the Beech Hill Block thus forfeiting its right to earn on the Block. An impairment of $129,777 was recorded for tThe full carrying value of these unproven property costs of $129,777 was considered impaired and transferred to the Canadian full cost pool. A ceiling test write-down was then recognized as the proven properties within the Canadian Costs cost center have been reduced to the ceiling test limit as described in Note 2(f).

In June 2008, the Company sold its 25% working interest in 9,692 net acres in the Phat City area of Montana (Rocky Mountains project) for cash of $800,503. The net book value of the Rocky Mountains project at the time of the sale was $830,508, which related to U.S. Rocky Mountain leasehold acquisition costs. As such, the Company recorded an loss on the sale of assets impairment of $30,005 which was transferred to the U.S. full cost pool.

In September 2008, the Company sold 20 of its 10,437 net Fayetteville acres for $13,000. The Company recorded an $8,000,000 impairment charge on the remaining land at October 31, 2008. The remaining unproven Fayetteville land was considered impaired and the carrying value of the unproven properties of $8,000,000 was transferred to the U.S. full cost pool. A related ceiling test write-down was then recognized at October 31, 2008 as the ceiling limit had already been reached under the test with the proven properties.

During the year ended January 31, 2008, the Company’s unproven property costs in the U.S. Rocky Mountains (Colorado and Wyoming) were considered impaired resulting in a costs of the carrying value of the unproven properties of $2,104,663 non-cash impairment loss being transferred to the U.S. full cost pool. and t The Company’s unproven property costs in the Fayetteville Shale Project were considered impaired resulting in a costs of the carrying value of the unproven properties of $6,527,498 non-cash impairment loss being transferred to the U.S. full cost pool. A related ceiling test write-down was then recognized as the ceiling limit had already been reached under the test with the proven properties.

In reference to the comment on gains and losses on sales or abandonments, we confirm that the sales met the criteria outlined in Rule 4-10(c)(6)(i) of Regulation S-X to be accounted for as a gain or loss as they accounted for more than 25% of the proved reserves or resulted in the full cost pool being reduced to nil.

As a small reporting company, you are required to present two years of financial statements, including all note disclosures required by GAAP. Accordingly, your disclosure of the changes in the standardized measure relating to proved oil and gas reserves should cover both years to comply with paragraph 33 of SFAS 69.

As noted on page F-17 of the notes to the financial statements, “the Company had two producing wells at the beginning of fiscal 2008 that were not assigned proved reserves”. Since there were no proved reserves at the beginning of fiscal 2008 and given the limited value of proven reserved at the end of fiscal 2008, the changes in the standardized measure was considered to be a non-material disclosure.

We note your disclosure explaining that in December 2008 you amended the terms of your December 28, 2005 convertible debentures, reducing the conversion price from $4.00 to $1.40 per share, also indicating partial conversion and settlement of the remaining balance followed, yielding a gain on extinguishment. We understand these instruments were originally issued with a beneficial conversion feature.

Tell us how your accounting for each aspect of these events, including the modification, the conversion, and settlement is consistent with GAAP, including the guidance of EITF 96-19, EITF 00-27, and APB 26, as applicable, and providing details sufficient to understand the basis for your view.

On December 18, 2008, we entered agreements with each lender to settle the December 28, 2005 debentures whereby the accrued interest was forgiven by the lenders and we agreed to pay $6,500,000 in cash and issue 2.5 million shares to the lenders (the fair value of the shares on December 18, 2008 was $0.20). The transaction was a settlement of convertible debt that upon issue had a beneficial conversion feature. The convertible debentures were not modified. A settlement agreement was reached with the lenders to accept cash of $6.5 million and shares with a market value of $0.5 million. The Company did not have the contractual right within the debenture agreement to settle the debentures with a variable number of common shares. As the transaction was a settlement not a modification, EITF 96-19 (Debtor's Accounting for a Modification or Exchange of Debt Instrument) did not apply. In future filings we will clarify the disclosures in the financial statements to eliminate the references to a modification of the debenture agreement.

In EITF 98-5 (Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios), paragraph 12, the Task Force considered situations in which a debt instrument containing the embedded beneficial conversion feature is extinguished prior to conversion. The Task Force reached a consensus that if an entity extinguishes a debt instrument that includes a beneficial conversion feature before conversion, it should allocate the reacquisition price between the debt component and the beneficial conversion feature. The amount allocated to the beneficial conversion feature is recorded as a reduction in additional paid-in capital. Furthermore, In EITF 00-27, paragraph 34, the Task Force reached a tentative conclusion that an entity should not allocate any amount of the reacquisition price to the conversion option if the conversion option had no intrinsic value required to be accounted for under EITF 98-5 or EITF 00-27.

On December 18, 2008, the conversion price was effectively $1.40 (calculated as the $3.5 million of principal settled (the $10 million principal less the cash payment of $6.5 million) divided by the 2.5 million shares issued to settle this portion of the debenture) and the trading price of the common shares was $0.20. The conversion option had no intrinsic value. As such, none of the reacquisition price was allocated to the beneficial conversion feature and additional paid-in capital did not have to be reduced.

Furthermore in EITF 98-5 (Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios), paragraph 12, the Task Force indicated that the entity should record an extinguishment gain or loss based on the difference between the reacquisition price allocated to the debt and the carrying value of the debt.

5.	We note that you identify investing cash outflows of $1.6 million and $678 thousand as “cash advances from partners.” It appears you may need to revise this line item to correspond with the activity shown. Also tell us why you believe these amounts are properly reported as investing activities.

As a part of our oil and gas investing activities, we received money in advance from our partners for drilling and completion operations on wells, which is booked to working capital on the balance sheet under prepaid expenses.

A drilling and completion operation on a well is an investing item and our net portion of the drilling costs will be booked to “oil and gas property expenditures” in the investing section; as such, we believe these working capital costs should also be allocated to the investing activities.

The Company acknowledges that: 1) the Company is responsible for the adequacy and accuracy of the disclosure in the filings; 2) staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filings; and 3) the Company may not assert this action as defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

		Suite 750, 521 3rd Ave SW Calgary, Alberta T3L 2W1 Phone: (403) 262-4471 Fax: (403) 262-4472

ATTN:	KARL HILLER, BRANCH CHIEF
	PAUL MONSOUR