February 14, 2013

Via EDGAR

Attention: Michael Fay, Division of Corporation Finance

Anne N. Parker

Branch Chief

United States Securities and Exchange Commission

100 F. Street, N.E.

Washington, D.C. 20549

Re: Triangle Petroleum Corporation

Form 10-K for the Fiscal Year ended January 31, 2012

Filed April 16, 2012

Form 10-K/A for the Fiscal Year ended January 31, 2012

Filed May 18, 2012

Form 10-Q for the Fiscal Quarter ended October 31, 2012

Filed December 10, 2012

File No. 001-34945

Dear Ms. Parker:

This letter responds to the staff’s comment letter dated January 31, 2013, regarding Triangle Petroleum Corporation’s Form 10-K for the fiscal year ended January 31, 2012, filed April 16, 2012, Form 10-K/A for the fiscal year ended January 31, 2012, filed May 18, 2012, and Form 10-Q for the fiscal quarter ended October 31, 2012, filed December 10, 2012 (File No. 001-34945). Triangle’s responses to the staff’s comments are set forth below:

Form 10-K for the Fiscal Year ended January 31, 2012

Properties, page 27

Proved Undeveloped Reserves, page 29

SEC Comment

1. We note the negative revision to your proved undeveloped reserves of 819 MBOE during 2012, compared to the 1,021 MBOE total at January 31, 2011. We also note that you provided the following explanation for this revision:

“Of the 19 gross (3 net) proved undeveloped locations at January 31, 2011, 13 gross (2.6 net) locations (with 840 net Mboe of proved reserves at January 31, 2012) were viewed by our Senior Reservoir Engineer as unproved as of January 31, 2012 because the available geological and engineering data did not support reasonable certainty of sufficient reserves to provide a positive PV10 Value, net of estimated future development costs.”

Please tell us the details of this revision and clarify the extent to which you had projected positive undiscounted future net cash flows in your evaluation of the volumes. Also tell us the capital costs you used to convert 53 MBOE to proved developed status.

Response

Of the 13 gross proved undeveloped locations removed, eight were gross proved undeveloped locations with modest economics at January 31, 2011 (being 1.3 net locations with a total PV10 value of only $1.1 million and undiscounted cash flow of $7.6 million, and 251Mbbl EUR/well). These eight proved undeveloped locations were located in two North Dakota areas, totaling approximately 23 square miles, with a certain third party serving as the operator for those locations and for four nearby producing wells.

In August 2011, members of Triangle management, including Triangle’s senior geologist, met with the operator’s representatives to discuss Triangle’s growing concerns with (1) further near-term development of the locations, (2) the operator’s proposed development approaches in that area, and (3) the operator’s difficulties with a few recently drilled wells in which Triangle had an interest. The meeting ended with Triangle going non-consent on certain proposed wells. The meeting and non-consents were key factors in declassifying those eight gross locations from proved undeveloped at January 31, 2012.

For the remaining five gross (1.3 net) proved undeveloped locations that were removed, our Senior Reservoir Engineer discussed the proved undeveloped location characteristics, including offset well production, with Mr. Tom Venglar, the primary technical person at Ryder Scott Petroleum Consultants (“Ryder Scott”) responsible for Ryder Scott’s estimation of Triangle’s proved reserves at January 31, 2012. In general, Mr. Venglar felt there was insufficient evidence at January 31, 2012 for him to view those undeveloped locations as proved — evidence such as direct offset wells with sufficient production performance. With consideration of those discussions with Mr. Venglar, our Senior Reservoir Engineer excluded those locations from the list of undeveloped locations for which Mr. Venglar would estimate proved reserves and future cash flows.

The 53 MBOE of proved undeveloped reserves at January 31, 2011 were for three Drill Spacing Units (“DSUs”) on which three gross (0.121 net) wells were drilled, completed and placed on production by January 31, 2012 at a total net cost of $1.65 million ($35.5 million gross, or $12 million per gross well).

SEC Comment

2. We note you report that extensions and discoveries of proved reserves added 756 MBOE to your PUD reserves in 2012. Given the significance of this addition to your reserve estimates, you should follow the guidance in Item 1202(a)(6) of Regulation S-K. This prescribes a general discussion of the technologies used to establish the appropriate level of certainty for reserves estimates from material properties included in the total reserves disclosed. Please expand your discussion to comply with this requirement.

Response

The 756 MBOE of additions to proved undeveloped reserves in 2012 appears in the Item 2 section “Oil and Natural Gas Reserves” to the Form 10-K. The first paragraph of that section explains that such additions are from estimation by Ryder Scott of our proved oil and natural gas reserves at January 31, 2012. The same paragraph explains that the estimates are further discussed in the Ryder Scott report filed as Exhibit 99.02 to the Form 10-K. We view the Ryder Scott report as providing the Item 1202(a)(6) general discussion of the technologies used by Ryder Scott to establish the appropriate level of certainty for reserve estimates of material properties included in the total reserves disclosed. The report, after discussion of generally accepted analytical procedures, performance-based methods, volumetric-based methods and analogy, discloses on its page 4 that all proved undeveloped reserves at January 31, 2012 were estimated by the analogy method utilizing pertinent well data supplied by Triangle or obtained by Ryder Scott from public data sources. Pertinent well data includes production from the well(s) that are one space away from the proved undeveloped location. In future filings, we will modify the disclosure in the “Oil and Natural Gas Reserves” section to expressly reference the methodology used to establish reserve estimates.

Drilling and Other Exploratory and Development Activities, page 31

SEC Comment

3. Please expand you table of wells drilled to disclose the number of dry exploratory and development wells, if any, to comply with Item 1205(a) of Regulation S-K.

Response

We did not include rows for dry exploratory and development wells in our table of wells drilled as we had none. In future filings, we will modify the table of wells to include such rows even if the disclosure is none.

SEC Comment

4. Please tell us the costs you incurred during 2012 that are related to drilling the 3.3 net wells that you report, compare the corresponding per well figure to the drilling cost per well used in computing the standardized measure shown on page 65, and explain your basis for any assumptions that contribute to significant differences.

Response

Total costs incurred during the fiscal year ended January 31, 2012 related to the drilling and completion of the 3.3 net wells was approximately $26.4 million, or approximately $8.0 million per net well (with total inception(spudding)-to-date costs of $9.7 million). Total future development costs for proved undeveloped well locations (17 gross, 2.6 net wells) were $23.4 million, or approximately $8.95 million per net well, with a few locations partially drilled by January 31, 2012. Future development costs were typically based on an AFE total gross drilling and completion cost of $9.9 million per well. We do not believe any assumptions contributed to significant differences.

Sales Volumes and Prices and Production Costs, page 32

SEC Comment

5. Please submit for review a reconciliation of the 2012 oil sales volumes of 109.5 MBO reported on page 32 and the 2012 oil production volumes of 93 MBO disclosed on page 63, along with an explanation for the difference.

Response

The 109,473 barrels of oil sales in fiscal year 2012 should have been reported as 92,694 barrels of oil sold because the 92,694 barrels corresponds to recorded revenues, which were based on conservative, yet reasonable, revenue accruals. The 109,473 barrels of oil had seemed reasonable based on weekly internal reports in January 2012 and December 2011 of well status and production rates by well.

Actual sales volumes were closer to 100,000 barrels of oil for fiscal year 2012 than 92,694 or 109,473 barrels. All our oil sales in 2012 were from non-operated interests. As a result, for many wells we had to estimate oil sales volumes for the last month in the reporting period, or estimate for two to four months for new wells. As permitted under North Dakota regulations, some operators report new wells’ sales volumes to the state but in a manner that keeps those volumes confidential until up to six months after the new well began production. We know that new wells might be shut-in for weeks due to drilling/completion of offset wells or installation of an artificial lift system. Consequently, we tried to be reasonably conservative in accruing oil revenues at January 31, 2012.

Now that most of our oil sales are from wells we operate, we know actual sales volumes for those wells within 20 days after the reporting period ends, and our revenue accrual estimates are closer to actuals overall.

Management acknowledges the discrepancy but views it as an immaterial matter that should not necessitate filing another amendment to the 10-K for fiscal year 2012. For the reasons described above, we expect that our future filings will contain revenue accrual estimates closer to actuals overall, and we will pay particular attention to this disclosure to avoid future discrepancies.

Financial Statements

Note 13 — Unaudited Supplemental Oil and Natural Gas Disclosures, page 61

Oil and Gas Reserve Information, page 63

SEC Comment

6. The guidance in FASB ASC 932-235-50-5 requires that you disclose an “appropriate explanation of significant changes” for line items in the reconciliation of your proved reserves. Please expand your disclosure to explain the details/circumstances of the significant revisions that you report, including those shown as “extensions and discoveries” during the fiscal year ending January 31, 2012.

Response

As disclosed on page 63 of the Form 10-K, the significant changes in the reconciliation of proved reserves are (1) the negative revisions of 932 Mbbl of crude oil and (2) the 1,268 Mboe (i.e., 1,154 Mbbl of crude oil and 686 Mmcf of natural gas) added for extensions and discoveries. Triangle management does not view the changes attributable to production to be significant changes, and such production is consistent with and explained by the financial statements’ reported revenues from sale of crude oil and natural gas.

Explanation of the Negative Revisions. Following the reconciliation is an explanation for 88% of the negative revisions, being the 819 Mbbl net revisions relating to proved undeveloped reserves. The majority of the remaining 113 Mbbl in negative revisions is attributable to Ryder Scott reducing proved reserves by 80% (86 Mbbl) for Triangle’s interest in three wells, based on their production performance in fiscal year 2012.

Explanation of the Changes for Extensions and Discoveries. Also following the reconciliation is a disclosure that 756 Mboe (60% of the 1,268 Mboe) is attributable to additions of proved undeveloped reserves, followed by a table describing circumstances as to the timing for drilling the locations and Triangle’s net interests in the needed development wells. An additional 279 Mboe (22% of the 1,268 Mboe) is attributable to Triangle’s 1.21 net well interest

in six gross wells that began producing in fiscal year 2012. The other 233 Mboe of reserve additions for extensions and discoveries relate to 41 gross (0.86 net) new wells that began producing in fiscal year 2012.

In future filings, we will expand our disclosure to include an appropriate explanation where management views changes to line items in the reconciliation of our proved reserves to be significant changes.

Form 10-K/A for the Fiscal Year ended January 31, 2012

Certain Relationships and Related Transactions..., page 85

SEC Comment

7. Please provide your analysis as to how you have complied with the standard set forth in Item 404 of Regulation S-K. In this regard, we note that your disclosure references transactions that “have materially affected or will materially affect” you or your related persons, whereas Item 404 of Regulation S-K requires disclosure of transactions where the amount involved exceeds $120,000 and in which any related person had or will have a direct or indirect material interest.

Response

Our disclosure that there have been no transactions, or proposed transactions, that “have materially affected or will materially affect us” applied the $120,000 figure in Rule 404(a) as the materiality threshold in making our determination. In future filings, if we have no related party transactions to disclose, we will modify our disclosure as follows:

“From February 1, [YEAR] to the present, there was no transaction or series of transactions, nor any currently proposed transaction, in which the amount involved exceeds $120,000 and in which any director, nominee for director, executive officer, or known beneficial holder of more than five percent of our outstanding common stock, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest.”

Form 10-Q for the Fiscal Quarter ended October 31, 2012

Financial Statements

Note 3 — Segment Reporting, page 10

SEC Comment

8. We note you perform pressure pumping services for wells operated by you and for wells operated by third parties, and you have credited the full cost pool to eliminate the gross profit relating to your working interests in these wells. Further, under Note 3 you state that you have acquired oil and gas properties during the current year. Please clarify for us whether you performed pressure pumping services for any properties acquired in the last year and, if so, how you considered and applied FASB ASC 932-10-S99- 1(c)(6)(IV)(B) (Rule 4-10(c)(6)(IV)(B) of Regulation S-X).

Response

Triangle’s subsidiary RockPile Energy Services, LLC (“RockPile”) began providing pressure pumping services in July 2012. Through October 31, 2012, RockPile had performed pressure pumping services for the completion of eight wells.

One of the eight wells was in a DSU in which Triangle had no economic interest, whereby Rule 4-10(c)(6)(iv) does not apply. No RockPile service income was credited against the full cost pool.

The most recent of the eight wells was in a DSU in which Triangle acquired its working interest within one year of the pressure pumping service provided by RockPile, but Triangle acquired the working interest by giving up (trading) economic interests in other DSUs where those economic interests had been acquired prior to March 31, 2011, or more than one year before the September 2012 contract for pressure pumping services on the well. Most of the pressure pumping services had been performed by October 31, 2012. Of the estimated $1,112,798 gross profit on RockPile’s services for the well through October 31, 2012, 67% was eliminated for Triangle’s 67% working interest in the well. The remaining $368,410 was not credited to the full cost pool at October 31, 2012 (the entry is immaterial). Instead, the $368,410 is being credited to the full cost pool in the fiscal 4th quarter ended January 31, 2013, along with that proportionate share of gross profit realized in November when the services were completed.

Six of the eight wells are located in four DSUs in which Triangle had acquired significant working interests (215 to 722 net acres per DSU of ~1,280 gross acres) prior to March 31, 2011 and more than 14 months before the particular work orders (the service contracts) with RockPile for pressure pumping services on the six wells. For those six wells, no RockPile service income was credited against the full cost pool, but intercompany revenues and gross profit were eliminated (as disclosed in the Segment note in the Form 10-Q for the fiscal quarter ended October 31, 2012).

For DSUs where Triangle acquired, more than one year before the service contract, at least 120 net acres (of a 1,280 acre DSU) and also acquired additional property interests in the spacing unit within one year of the contract (through transactions unrelated to the service contract),

Triangle does not credit service income against the full cost pool. Such accounting takes into consideration the following:

1. Rule 4-10(c)(6)(iv)(B) reads, “When the registrant acquired an interest [not its interests] in the properties at least one year before the date of the service contract through transactions unrelated to the service contract, income from such contract may be recognized subject to the general provisions for elimination of intercompany profits under generally accepted accounting principles.”

2. Additional working interests come in various ways (that are sometimes not entirely within the control of Triangle), such as (i) non-consents by other working interest owners prior to drilling or (ii) last-minute leasing by small mineral owners who would otherwise be working interest owners in the DSU.

a. Triangle acquired 722 net acres (56.4%) of a certain DSU by March 31, 2011 and (because of that old interest) took on the drilling cost of an additional 24.2% of the DSU when a much larger U.S. oil company opted in February 2012 for its 24.2% DSU working interest to not participate in drilling the DSU’s first well (completed in August 2012). That addition and miscellaneous small additions gave Triangle 84.3% of the well cost, and Triangle eliminated 84.3% of the revenues and gross profit under the general GAAP requirement for elimination of intercompany profits. However, it seems unreasonable and contrary to the concept expressed in Rule 4-10 (c)(6)(iv)B for the additional acquired working interests to result in Triangle crediting its full cost pool for the other 15.7% of RockPile gross profit attributable to property interests of other third party working interest owners who elected to participate in drilling the well.

b. We have acquired additional working interests by “acreage swaps”, trading old small acreage positions in other potential DSUs for acreage in DSUs where we already hold a significant position and wished to proceed in having a well drilled. In one case last year, the respective Land Departments of Triangle and a much larger oil company had reached an oral agreement in August 2011 for trading working interests of approximately 854 net acres, but the larger company took several months to formally approve the swap, delaying the swap closing to May 30, 2012. The working interests of 854 net acres received in the swap were for additional working interests in five DSUs in which Triangle had owned more than 10% of each DSU’s total working interest both before the swap and more than one year before any contract with RockPile to provide pressure pumping services.

* * * * * * * *

In connection with the above response to the staff’s comment, Triangle acknowledges that:

· Triangle is responsible for the adequacy and accuracy of the disclosure in the filing;

· Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

· Triangle may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Sincerely,

/s/ Jonathan Samuels
Jonathan Samuels
President and Chief Executive Officer