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TPLM > SEC Filings for TPLM > Form 10-K on 1-May-2013All Recent SEC Filings

Show all filings for TRIANGLE PETROLEUM CORP | Request a Trial to NEW EDGAR Online Pro

Form 10-K for TRIANGLE PETROLEUM CORP


1-May-2013

Annual Report


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this annual report contain additional information that should be referred to when reviewing this material.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties that could cause actual results to differ from those expressed. We encourage you to revisit the Forward-Looking Statements section in Part I of this annual report.

Overview

We are an independent energy company focused on the exploration, acquisition, and production of unconventional shale oil and natural gas resources in the United States. Our oil and natural gas reserves and operations are primarily concentrated in the Bakken Shale and Three Forks formations of the Williston Basin in North Dakota and Montana. As of January 31, 2013, we held leasehold interests in approximately 86,000 net acres primarily in McKenzie and Williams Counties of North Dakota and Roosevelt and Sheridan Counties of Montana. Having identified an area of focus in the Bakken Shale and Three Forks formations that we believe will generate attractive returns on invested capital, we are continuing to explore further opportunities in the region.

In our core area of North Dakota and eastern Montana, Triangle is directing resources toward its operated program to develop its approximately 30,000 net acres, primarily in McKenzie and Williams County, North Dakota. In Roosevelt County, Montana, our Station Prospect is a largely contiguous position within the thermally mature area of the Williston Basin. Our approximate 50,000 net acre position in the Station Prospect is predominantly operated acreage with an average remaining lease term of four years and provides us with a development area that we believe is scalable for the future.

With a focus on establishing an efficient operated development program, we have pursued select vertical integration opportunities in an effort to realize cost savings and strategic advantages. The Williston Basin is a resource constrained region in terms of oilfield services, infrastructure and human capital, resulting in challenging operating conditions for relatively smaller operators, such as Triangle. Pressuring pumping services and fluid logistics are critical to achieving operational efficiencies in the basin and represent material cost centers for exploration and production companies. As a result, we have targeted these verticals for integration via RockPile and Caliber. Having control over these areas of the value chain permits us to direct the availability and timing of well completion services and to transport oilfield fluids through pipeline.

RockPile, a wholly-owned subsidiary initially capitalized in September and October 2011, is a provider of hydraulic pressure pumping and complementary well completion services to oil and natural gas exploration and production companies in the Williston Basin of North Dakota and Montana. The Williston Basin is widely regarded as one of the most demanding basins in North America due to the harsh environment, lack of established infrastructure, and limited availability of qualified personnel in the region. RockPile's management team has extensive experience providing oilfield services in the Williston Basin.

Pressure pumping involves the use of a technologically sophisticated set of mobile equipment mounted on tractor trailer chassis. RockPile purchased its first set of equipment, collectively known as a "spread", in the first half of 2012. RockPile's first spread commenced 12-hour operations in July 2012 and 24-hour operations in September 2012. From commencement of operations in July 2012 through January 31, 2013, RockPile completed 363 stages on 12 wells for Triangle and 132 stages on 5 wells for third-parties for a total of 495 stages on 17 wells. RockPile ordered a second spread during the first quarter of fiscal year 2014, which is currently on schedule to be placed into production in the second quarter of fiscal year 2014.

Caliber is a joint venture with First Reserve Energy Infrastructure Fund ("FREIF") created in October 2012, which was capitalized through initial funding commitments of $100 million in equity capital contributions ($70 million from FREIF, $30 million from Triangle). Caliber is managed and governed by its general partner, Caliber Midstream GP, LLC, of which FREIF and Triangle each own a 50% non-economic interest and share governance equally. Caliber is an energy infrastructure company that provides crude oil and natural gas gathering, transportation, treating and processing; produced water transportation and disposal in Caliber-owned and/or operated injection wells; and freshwater sourcing and transportation by pipeline linked to various points of supply to


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producers in the Williston Basin of North Dakota and Montana. We believe that Caliber's integrated solution to water, oil and natural gas transportation and processing benefits producers by reducing the costs and environmental impacts of trucking and reducing or eliminating the emissions generated by flaring produced natural gas.

Caliber began water transportation and disposal operations in January 2013 and expects to have all business lines in service by the third quarter of fiscal year 2014. Caliber is currently constructing its Phase 1 pipeline system and central facility in McKenzie County, North Dakota and plans to expand the Phase 1 pipeline system in McKenzie County and to build new infrastructure in other counties of North Dakota and Montana as needed by TUSA and third-party customers.

Proved Reserves

Fiscal year 2013 proved reserves grew 891% to 14,637 Mboe, up from 1,477 Mboe at fiscal year-end 2012. Proved reserves were 41% developed at fiscal year-end 2013 compared to 39% at fiscal year-end 2012. Reserves added from extensions and discoveries totaled 12,669 Boe. In total, reserve additions were comprised of 85% oil and 15% natural gas. All of our proved reserves are located in the Bakken Shale and Three Forks formations in North Dakota or in Montana close to the North Dakota border.

The process of estimating quantities of oil and natural gas reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, contractual arrangements and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time.

Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data make these estimates generally less precise than other estimates included in financial statement disclosures. See Note 22 - Unaudited Supplemental Oil and Natural Gas Disclosures to the Consolidated Financial Statements of this annual report for further discussion regarding our proved reserves.

Results of operations for the year ended January 31, 2013 compared to the year ended January 31, 2012

For the fiscal year ended January 31, 2013, we recorded a net loss attributable to common stockholders of $13.8 million ($0.31 per common share, basic and diluted) as compared to a net loss attributable to common stockholders of $24.3 million ($0.60 per common share, basic and diluted) for the fiscal year ended January 31, 2012.


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Oil and natural gas sales and production costs for each year are summarized in the table that follows. The fiscal year 2012 information shows oil sales volumes that correspond to the $8,008,912 in oil revenues for fiscal year 2012.

                                                                2013             2012
U.S. oil and natural gas operations
Oil sold (barrels)                                                451,784           92,694
Average oil price per barrel                                $       85.29    $       86.40
Oil revenue                                                 $  38,532,886    $   8,008,912
Natural gas sold (mcf)                                            188,044           11,758
Average natural gas price per mcf                           $        4.78    $        9.06
Natural gas revenue                                         $     899,290    $     106,557
Natural gas liquids sold (gallons)                                212,266            9,076
Average natural gas liquids price per gallon                $        0.86    $        2.26
Natural gas liquids revenue                                 $     182,035    $      20,503
Total oil, natural gas and natural gas liquids revenues     $  39,614,211    $   8,135,972
Less production taxes                                          (4,492,836 )       (896,062 )
Less lease operating expense (excluding production
taxes)                                                         (3,469,413 )       (901,240 )
Less gathering, transportation and processing expense            (150,530 )        (21,510 )
Less impairment of oil and natural gas properties                       -       (6,000,000 )
Less oil and natural gas amortization expense                 (13,548,000 )     (3,022,000 )
Less accretion of asset retirement obligations                    (21,119 )         (6,950 )
Income (loss) from U.S. oil and natural gas production      $  17,932,313    $  (2,711,790 )
Gross profit from pressure pumping services                     3,016,573                -
Other revenues                                                    340,081                -
Income (loss) from U.S. operations                          $  21,288,967    $  (2,711,790 )

Canadian oil and natural gas operations
Lease operating expense                                           (96,947 )       (640,650 )
Less impairment of oil and natural gas properties                       -       (4,416,202 )
Accretion of asset retirement obligations                        (162,382 )       (159,975 )
Loss from Canadian oil and natural gas operations                (259,329 )     (5,216,827 )
Income (loss) from operations                                  21,029,638       (7,928,617 )
U.S. and Canadian other income (expense)
Loss on derivative activities                                  (3,570,151 )              -
Other income (expense)                                             74,396          551,824
Interest expense                                               (2,818,118 )              -
Foreign exchange loss                                                (656 )        (21,938 )
Less depreciation of furniture and equipment                     (407,746 )        (91,872 )
Less general and administrative expenses                      (28,791,092 )    (16,932,340 )
Net loss                                                    $ (14,483,729 )  $ (24,422,943 )
Total U.S. barrels of oil equivalent ("boe") sold                 488,179           94,870
U.S. oil and natural gas revenue per boe sold               $       81.15    $       85.76
U.S. production tax per boe sold                            $        9.20    $        9.45
U.S. other lease operating expense per boe sold             $        7.11    $        9.50
U.S. gathering, transportation and processing expense
per boe sold                                                $        0.31    $        0.23
U.S. amortization expense per boe sold                      $       27.75    $       31.85

Oil and Natural Gas Sales Revenue

Production revenues increased to $39.6 million for the fiscal year ended January 31, 2013 from $8.1 million for the fiscal year ended January 31, 2012 due to a 415% increase in production volumes, offset by a 5% reduction in oil and natural gas prices on a per Boe basis. The increase in production volumes added approximately $31.9


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million in revenues, and the decrease in price per Boe reduced revenues by approximately $0.4 million.

Total production volumes increased to 488.2 Mboe (1,334 Boepd) for the fiscal year ended January 31, 2013 from 94.9 Mboe (260 Boepd) for the fiscal year ended January 31, 2012, primarily due to the addition of approximately 240.2 Mboe from our operated drilling program as well as a 153.1 Mboe (161% ) increase in production from our non-operated portfolio. Additional information concerning production is in the following table:

                  Fiscal Year Ended January 31, 2013         Fiscal Year Ended January 31, 2012
                 Oil     Natural Gas   Liquids   Total      Oil     Natural Gas   Liquids   Total
               (MBbls)     (MMcf)      (Mgal)    (Mboe)   (MBbls)     (MMcf)      (Mgal)    (Mboe)
Operated           240             -         -      240         -             -         -        -
Non-Operated       212           188       212      248        93            12         9       95
Total              452           188       212      488        93            12         9       95

Pressure Pumping Services

RockPile commenced operations in July 2012. We formed RockPile with strategic objectives to have both greater control over our largest cost center as well as to provide locally-sourced, high-quality completion services to Triangle and other operators in the Williston Basin. RockPile's focus from formation through January 31, 2013 has mostly been on procuring new pressure pumping equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, and establishing third-party customers in the Williston Basin. Results of operations are affected by a number of variables including drilling and stimulation activity in the Williston Basin, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers. RockPile's profitability is primarily driven by the ability to obtain third-party work, equipment utilization, and the pricing environment for our services.

For the year ended January 31, 2013, RockPile performed hydraulic fracturing services for Triangle and three distinct third-party customers. This work resulted in 17 total well completions: 12 for Triangle and five for third-parties. All Triangle wells were completed using plug-and-perf applications. Four third-party wells were completed using a sliding sleeve application and one well was completed using a plug-and-perf application. RockPile revenue is comprised of service revenue, which is what we charge for equipment and labor, and materials revenue, which is what we charge for chemicals and proppant. Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), trucking charges, material transloading fees, railroad related costs, insurance, repairs and maintenance charges and safety costs. Direct costs as a percentage of revenue will vary based upon equipment utilization.

The $3,016,573 of gross profit from pressure pumping services in fiscal year ended 2013 is after (i) elimination of $10 million in intercompany gross profit and (ii) full cost accounting non-recognition of $1.8 million of income relating to pressure pumping services for third parties through October 31, 2012. For the fourth quarter of fiscal year 2013, there was no additional non-recognition of service income under full cost accounting because the eliminated intercompany gross profit on pressure pumping for each TUSA-operated well exceeded that well's total service income, due to TUSA's high working interests (averaging 84.2%) in operated wells completed in that quarter. See Note 4 - Segment Reporting in the accompanying Consolidated Financial Statements and see Full Cost Accounting's Non-recognition of Service Income with Third Parties in Certain Circumstances that begins on page 60.

Hedging Activities

In fiscal year 2013, the Company entered into commodity derivative instruments, primarily utilizing single-day puts and costless collars to reduce the effect of price changes on a portion of our future oil production. The Company's commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the gain (loss) on derivative activities line on the consolidated statement of operations. We value our derivative instruments by obtaining independent market quotes, as well as using industry-standard models that consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures.


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The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate. We utilize our valuations to assess the reasonableness of counterparties' valuations. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant's view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. The change in fair value of our derivative instruments resulted in a $3.6 million unrealized loss on derivative activities for fiscal year 2013. For additional discussion, please refer to Note 13 - Commodity Derivative Instruments under Item 8 of this annual report.

Production Taxes

Total production taxes increased to $4.5 million for the fiscal year ended January 31, 2013 from $0.9 for the fiscal year ended January 31, 2012. Production taxes are primarily based on the wellhead values of production and the increase in production taxes is directly related to a 387% increase in production revenues. Production taxes as a percentage of oil and natural gas sales were 11.3% for the fiscal year ended January 31, 2013 and 11.0% for the fiscal year ended January 31, 2012. These rates are consistent with the published production tax rates in North Dakota, the primary source of our production.

Lease Operating Expense

Lease operating expense for U.S. operations ("LOE") decreased to $7.11 per Boe for the fiscal year ended January 31, 2013 from $9.50 per Boe for the fiscal year ended January 31, 2012. The decrease is primarily the result of lower LOE on non-operated wells which decreased from $9.50 per Boe to $5.17 per Boe. For most of our non-operated wells the largest LOE component is water disposal. An increase in availability of trucking and third-party disposal facilities in the Williston Basin has reduced this cost on a per unit basis. Offsetting the reduction in non-operated LOE costs were operated LOE costs of $9.15 per Boe. Included in the operated LOE rate are non-recurring costs for equipment rentals as well as two workovers.

Gathering, Transportation and Processing

Gathering, transportation and processing ("GTP") expenses increased to $0.31 per Boe for the fiscal year ended January 31, 2013 from $0.23 per Boe for the fiscal year ended January 31, 2012. Currently, all GTP costs are associated with non-operated wells and are primarily for the gathering and transportation of oil and natural gas. GTP costs were $0.61 and $0.23 per non-operated Boe for the fiscal years ended 2013 and 2012, respectively. This increase is primarily the result of an increase in natural gas being gathered and transported instead of being flared. Going forward we expect GTP costs to increase as natural gas gathering, transportation and processing infrastructure becomes available for operated wells during the second half of fiscal year 2014.

Depletion, Depreciation, Amortization and Accretion ("DD&A") Expense

Oil and natural gas amortization expense increased to $13.5 million for the fiscal year ended January 31, 2013 from $3.0 million for the fiscal year ended January 31, 2012. The increase is primarily related to a 415% increase in production for fiscal year 2013 compared to fiscal year 2012. The increase in production accounted for an additional $12.5 million in DD&A expense, which was offset by a reduction of $2.0 million due to a decreased DD&A rate. The decrease in the amortization rate is due to proved reserves increasing at a higher rate than the amortization base increased. During fiscal year 2013 proved reserves increased approximately 891% while the amortization base increased approximately 632%.

Depreciation expense increased to $1.6 million for the fiscal year ended January 31, 2013 from $.09 million for the fiscal year ended January 31, 2012. This increase is primarily attributable to the depreciation of RockPile operating equipment as the equipment was placed into service in July 2012.


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General and Administrative Expenses

The following table summarizes increases in general and administrative expenses for the fiscal years 2013 compared with 2012. The increases are primarily due to increases in the number of employees as we continued to expand our acquisition, exploration, development and production activities in North Dakota and Montana during fiscal year 2013.

                                                                                     Increase
                                                       2013            2012         (Decrease)
General and administrative, excluding RockPile:
Stock-based compensation                           $  5,848,648    $  7,567,312    $ (1,718,664 )
Salaries, benefits and consulting fees                7,067,799       4,908,670       2,159,129
Office rent and other office costs                    1,563,965       1,448,981         114,984
Professional fees                                     2,084,448       1,517,735         566,713
Public company costs                                    458,939         607,500        (148,561 )
                                                     17,023,799      16,050,198         973,601
RockPile general and administrative expense          11,767,293         882,142      10,885,151
Total general and administrative expense           $ 28,791,092    $ 16,932,340    $ 11,858,752

RockPile's general and administrative costs of $11.8 million increased from $0.8 million in fiscal year 2012. This increase is primarily attributable to increased compensation and benefit costs for personnel in RockPile's headquarters and field offices as RockPile built its team and commenced operations in July 2012.

Interest Expense

The $2.8 million in interest expense consists of approximately $0.2 million in interest and amortized fees related to the TUSA credit facility and approximately $3.0 million in accrued interest and amortized fees related to our 5% convertible note with NGP. The total $3.2 million in interest expense is reduced by approximately $0.4 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. See Note 12 - Long-Term Debt for additional information regarding our credit facility and convertible note.

Income Taxes

Our fiscal year 2013 provision for deferred income taxes is zero due to recognition of 100% valuation allowances against our net deferred tax assets of $35.0 million and $29.2 million at January 31, 2013 and 2012, respectively. If facts and circumstances indicate that all or a portion of the deferred tax asset is more likely than not to be realized in the future, then the valuation allowance would be correspondingly reduced and a deferred tax benefit recognized.

Results of operations for the year ended January 31, 2012 compared to the year ended January 31, 2011

For the fiscal year ended January 31, 2012, we recorded a net loss attributable to common stockholders of $24.3 million ($0.60 per common share, basic and diluted) as compared to a net loss attributable to common stockholders of $20.3 million ($1.63 per common share, basic and diluted) for the fiscal year ended January 31, 2011.


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Oil and natural gas sales and production costs for each year are summarized in the table that follows. The fiscal year 2012 information shows oil sales volumes that correspond to the $8,008,912 in oil revenues for fiscal year 2012.

                                                                2012             2011
U.S. oil and natural gas operations
Oil sold (barrels)                                                 92,694            6,174
Average oil price per barrel                                $       86.40    $       74.20
Oil revenue                                                 $   8,008,912    $     458,111
Natural gas sold (mcf)                                             11,758           23,689
Average natural gas price per mcf                           $        9.06    $        4.46
Natural gas revenue                                         $     106,557    $     105,559
Natural gas liquids sold (gallons)                                  9,076                -
Average natural gas liquids price per gallon                $        2.26    $           -
Natural gas liquids revenue                                 $      20,503    $           -
Total oil and natural gas revenues                          $   8,135,972    $     563,670
Less production taxes                                            (896,062 )        (94,654 )
Less lease operating expense (excluding production
taxes)                                                           (901,240 )        (30,696 )
Less gathering, transportation and processing expense             (21,510 )        (14,535 )
Less impairment of oil and natural gas properties              (6,000,000 )              -
Less oil and natural gas amortization expense                  (3,022,000 )        (96,000 )
Less accretion of asset retirement obligations                     (6,950 )         (5,148 )
Income (loss) from U.S. oil and natural gas production         (2,711,790 )        322,637

Canadian oil and natural gas operations
Lease operating expense                                          (640,650 )        (31,628 )
Impairment of oil and natural gas properties                   (4,416,202 )    (14,917,356 )
Gain on sale of oil and natural gas properties                          -        1,006,294
Accretion of asset retirement obligations                        (159,975 )       (245,171 )
Loss from Canadian oil and natural gas operations              (5,216,827 )    (14,187,861 )
Loss from operations                                           (7,928,617 )    (13,865,224 )
U.S. and Canadian other income (expense)
Other income (expense)                                            551,824           59,373
Foreign exchange gain (loss)                                      (21,938 )         35,615
. . .
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