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TPLM > SEC Filings for TPLM > Form 10-Q on 9-Sep-2013All Recent SEC Filings

Show all filings for TRIANGLE PETROLEUM CORP

Form 10-Q for TRIANGLE PETROLEUM CORP


9-Sep-2013

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

We or our representatives may make forward-looking statements, oral or written, including statements in this Quarterly Report on Form 10-Q, press releases and filings with the Securities and Exchange Commission ("SEC"), regarding, among other things, estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and natural gas production, the number of wells we anticipate drilling in the future, the potential number of operated drill spacing units and well locations on our acreage, the timing of anticipated drilling, our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward-looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and natural gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors, including but not limited to, those set forth among the Risk Factors noted in our Fiscal 2013 Form 10-K and in this Quarterly Report on Form 10-Q under the heading "Item 1A. Risk Factors". All subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

Overview

Triangle Petroleum Corporation ("Triangle" or the "Company" or "we" or "our") is a growth-oriented, independent energy company focused on the exploration, development 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 July 31, 2013, we held leasehold interests in approximately 86,000 net acres in the Williston Basin, approximately 36,000 of which are in our core focus area primarily in McKenzie and Williams Counties, North Dakota, which we refer to as our "Core Acreage." Our Core Acreage has a high oil saturation, is slightly over-pressured, and has the potential for multiple benches. The remaining 50,000 net acres comprise our "Station Prospect" located in Roosevelt and Station Counties, Montana.

Our primary strategy is to grow our production volumes through the efficient development of our operated Bakken Shale and Three Forks drilling inventory. We use pad drilling, which increases efficiencies while controlling costs and minimizing environmental impact. We also use advanced completion, collection and production techniques that optimize reservoir production while reducing costs. We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation ("TUSA"). Our estimated proved oil and gas reserves as of July 31, 2013 totaled 22,080 Mboe.

Our daily production for the fiscal quarter ended July 31, 2013 averaged approximately 4,287 Boepd of which 2,799 Boepd is net to our interests in wells we operate ("operated wells") and 1,488 Boepd is from wells operated by third-parties ("non-operated wells"). All production in fiscal year 2014 is from wells in North Dakota, primarily from the Bakken Shale formation and, to a lesser extent, the Three Forks formation.

In an effort to better control key operations, reduce costs, and retain supply chain value in the Williston Basin, which we view as a resource-constrained and cost-heavy basin, we formed RockPile Energy Services, LLC, or RockPile, our wholly-owned oilfield services subsidiary, and entered into a 30% owned joint venture arrangement with First Reserve Energy Infrastructure Fund, or FREIF, to form Caliber Midstream Partners LP, or Caliber. RockPile provides pressure pumping services, which we believe lowers our realized well completion costs and affords us greater control over completion schedules, quality control and pay cycles. Caliber currently provides produced water transportation and crude oil and natural gas gathering services and is expected to provide natural gas processing services during the third quarter of fiscal year 2014. We expect that Caliber will reduce the cost and environmental impacts of trucking oil and water and


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reduce or eliminate the emissions generated by the flaring of produced natural gas. In addition to providing services to TUSA, each of RockPile and Caliber are focused on growing their respective businesses through securing independent, third-party contracts.

Summary of operating and financial results for six months ended July 31, 2013:

Production volumes totaled 635,929 Boe for the six months ended July 31, 2013. This is an increase of 280% from 167,360 Boe for the six months ended July 31, 2012.

Oil and natural gas sales were $55.7 million compared to $12.7 million for the six months ended July 31, 2012.

Our average realized oil price increased to $90.11 per barrel compared to $80.85 per barrel in the first six months of fiscal year 2013.

Proved reserves were an estimated 22,080 Mboe at July 31, 2013 compared to 14,637 Mboe at January 31, 2013.

Net income of $12.0 million for the six months ended July 31, 2013 compared to a net loss of $4.5 million for the six months ended July 31, 2012.

Cash flow provided by operating activities was $31.4 million for the six months ended July 31, 2013 compared to cash provided by operating activities of $4.0 million for the six months ended July 31, 2012.

TUSA's credit facility was syndicated with an increased maximum credit availability of $500.0 million and a borrowing base of $165.0 million at July 31, 2013.

Drilled and completed 13 gross (9.24 net) operated wells during the first six months of fiscal year 2014.

Recent Events

Acquisition of Oil and Gas Assets

On August 28, 2013, TUSA acquired from an unaffiliated oil and gas company certain oil and gas leaseholds located in McKenzie County, North Dakota comprising approximately 6,200 net acres, and various other related rights, permits, contracts, equipment and other assets for total consideration of $83.8 million. The effective date for the Acquisition was July 1, 2013. See Note 15
- Subsequent Events under Item 1 of this Quarterly Report for further discussion.

In addition to the above acquisition, subsequent to July 31, 2013, TUSA entered into various agreements with unrelated parties to acquire an aggregate of approximately 2,306 net acres for aggregate consideration of approximately $19.6 million plus 325,000 shares of our common stock. See Note 15 - Subsequent Events under Item 1 of this Quarterly Report for further discussion.

Production from the above acquisitions averaged 1,150 Boe per day, based on produced volumes in June 2013. The acquired leasehold includes seven to nine controlled drilling spacing units and is largely held by production. The interests are contiguous to existing acreage in our core area of operations and are located adjacent to or within close proximity to the operations of Caliber, which we expect will provide synergies. The acquisitions increase (i) our total core acreage to approximately 45,000 net acres, and (ii) net production to approximately 5,650 Boe per day, assuming our estimated 21-day sales volumes, as of July 31, 2013. Additionally, the acquired leasehold, combined with successful down-spacing tests for Triangle and other operators, increases our inventory from six years to eight to twelve years.

Public Equity Offering

On August 8, 2013, we entered into an underwriting agreement (the "Underwriting Agreement") with Wells Fargo Securities, LLC, as representative of the several underwriters named therein (collectively, the "Underwriters"), pursuant to which we agreed to issue and sell to the Underwriters in a firm commitment offering (the "Offering") 15,000,000 shares of the Company's common stock, par value $0.00001 per share at a price to the public of $6.25 per share. Pursuant to the Underwriting Agreement, the Company also granted the Underwriters a 30-day over-allotment option to purchase up to an additional 2,250,000 shares of common stock at the same public offering price. The Offering was made pursuant to the Company's effective registration statement on Form S-3 (Registration Statement No. 333-171958) previously filed with the Securities and Exchange Commission on January 31, 2011. The Offering closed on August 14, 2013. The Underwriters exercised their over-allotment option on September 6, 2013, which will close on September 11, 2013. The total net proceeds to the Company from the Offering and the exercise of the over-allotment option will be approximately


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$101.8 million, after deducting underwriting discounts and commissions and other estimated offering expenses payable by the Company. See Note 15 - Subsequent Events under Item 1 of this Quarterly Report for further discussion of this transaction.

Private Placement

On August 28, 2013, the Company issued to ActOil Bakken, LLC ("ActOil"), an affiliate of Teachers Insurance and Annuity Association of America, 11,350,000 shares of common stock at $7.20 per share for gross proceeds of $81.7 million and concurrently entered into a Rights Agreement with the purchaser. See Note
15 - Subsequent Events under item 1 of this Quarterly Report for further discussion of this transaction.

Amendment to Senior Credit Facility and Increase in Borrowing Base

On July 31, 2013, TUSA entered into a first amendment to its Amended and Restated Credit Agreement to, among other things, increase its hedging capacity and make the necessary amendments to enable TUSA to enter into a second lien credit facility. Concurrent with the amendment, the borrowing base under the senior credit facility was increased to $165.0 million.

Reserve Update

As of July 31, 2013, we have estimated proved reserves of 18.7 million barrels of oil and 20.2 million cubic feet of natural gas, or 22.1 million barrels of oil equivalent (MMboe). Pro forma for the acquisitions of oil and gas assets after July 31, 2013, we have estimated proved reserves of 24.3 million barrels of oil and 24.1 million cubic feet of natural gas, or 28.4 million barrels of oil equivalent (MMboe). Our reserve quantities are comprised of 85% crude oil and 15% natural gas. The July 31, 2013 proved reserves (prior to the addition of reserves associated with the oil and gas assets acquired after July 31, 2013) reflect a 51% increase over the January 31, 2013 proved reserves of 14,637 MMboe. Our proved oil and gas reserves at July 31, 2013 and the reserve estimates for the acquisitions of oil and gas assets after July 31, 2013 were estimated by our in-house senior reservoir engineer, who has been a Registered Professional Engineer in Colorado since 1984 and has over 30 years' experience as a petroleum engineer. The following table summarizes our actual and pro forma reserves as of July 31, 2013:

                           % of                         July 31,   January 31,
                         Reserves     Oil       Gas       2013        2013          %
Reserve Category          (Mboe)    (MBbls)   (MMcf)      MBoe        MBoe       Change
July 31, 2013 Assets
Proved Developed               45 %   8,413     8,665      9,857         5,969        65 %
Proved Undeveloped             55 %  10,296    11,567     12,223         8,668        41 %
Total Proved                  100 %  18,709    20,232     22,080        14,637        51 %

Pro Forma for
Acquisitions after
July 31, 2013
Proved Developed               42 %  10,291     9,509     11,876         5,969        99 %
Proved Undeveloped             58 %  14,051    14,596     16,484         8,668        90 %
Total Proved - Pro
Forma                         100 %  24,342    24,105     28,360        14,637        94 %

In estimating the proved reserves presented above, we used the Securities and Exchange Commission's definition of proved reserves. Projected future cash flows were based on economic and operating conditions as of July 31, 2013 except that future oil and natural gas prices used in the projections reflected an unweighted arithmetic average of the first-day-of-the-month price for each month during the 12-month period prior to that date. For the purposes of preparing the Company's actual proved reserves at July 31, 2013, such average pricing was $87.36 per barrel of oil and $5.56 per mcf of natural gas, and at January 31, 2013 was $84.76 per barrel of oil and $5.23 per Mcf of natural gas. For the reserves acquired after July 31, 2013, added to our actual reserves to arrive at the pro forma presentation presented above, such additional proved reserves were calculated using a price of $86.33 per barrel of oil and $4.51 per mcf of natural gas,


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which represented the unweighted average of the first-day-of-the-month prices for each of the twelve months ending June 30, 2013, the most recent twelve-month period prior to the July 1, 2013 effective date for such acquisitions.

Volumes of reserves that will be actually recovered and cash flows that will be actually received from actual production may differ significantly from the proved reserve estimates and the related projected cash flows, respectively. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any proved reserve estimate is a function of the quality of available data, of engineering and geological interpretation and judgment, and of the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, proved reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Drilling and Completions



The following tables summarize the wells spud and completed during the three and
six months ended July 31, 2013:



                        For the Three Months Ended July 31, 2013
                              Spud                    Completed
                        Gross          Net          Gross        Net
Operated wells                 9         5.7               8     5.2
Non-operated wells            18         1.1              22     1.4
                              27         6.8              30     6.6

For the Six Months Ended July 31, 2013

                              Spud                 Completed
                       Gross         Net         Gross       Net
Operated wells               18        11.9            13    10.2
Non-operated wells           44         2.8            52     3.4
                             62        14.7            65    13.6

Properties, Plan of Operations and Capital Expenditures

We own operated and non-operated leasehold positions in the Williston Basin. As of July 31, 2013, we have completed a total of 29 (18.82 net) operated wells since entering the Williston Basin. During fiscal year 2014, we anticipate drilling approximately 33 (18.94 net) operated wells and completing approximately 30 (18.46 net) operated wells in North Dakota or eastern Montana. Of the 30 wells expected to be completed in fiscal year 2014, we have completed 13 gross wells and had an additional 5 gross wells in progress as of July 31, 2013. Twenty-seven of the wells are planned to be in the Bakken Shale and three are planned for the Three Forks formation. We also have economic interests in approximately 227 (10.84 net) non-operated wells.


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We are currently running a three-rig drilling program, which we anticipate continuing for the remainder of fiscal year 2014. The focus of our drilling program is on our Core Acreage in McKenzie and Williams Counties.

Our oil and natural gas property expenditures are summarized in the following tables for the periods indicated (in thousands):

                                   Six Months Ended July 31,
                                     2013             2012
Leasehold acquisitions          $        6,200    $      10,978
Drilling and Completion
Operated                               102,900           44,862
Non-operated                            25,381           11,045
Facilities and Infrastructure            2,424                -
                                $      136,905    $      66,885

U.S. Leaseholds

As of July 31, 2013, we had approximately 2,300 lease agreements representing approximately 211,000 gross and 86,000 net acres in the Williston Basin of North Dakota and Montana. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

                         Developed Acres     Undeveloped Acres      Total Acres
                         Gross      Net       Gross       Net      Gross     Net
North Dakota             76,623    19,794      49,955    11,950   126,578   31,744
Montana                   2,096       573      82,286    54,114    84,382   54,687
Total Williston Basin    78,719    20,367     132,241    66,064   210,960   86,431

We are subject to lease expirations if we or the operator of our non-operated acreage do not commence the development of operations within the agreed terms of our leases. All of our leases for undeveloped acreage will expire at the end of their respective primary terms except for leases where we either (i) make extension payment(s) under the lease terms, (ii) renew the existing lease,
(iii) establish commercial production paying royalties to the lessor or
(iv) exercise some other "savings clause" in the respective lease. We expect to establish production from most of our acreage prior to expiration of the applicable lease terms. However, there can be no guarantee we will do so.

Other Properties

We have an 87% working interest in approximately 474,625 gross acres (approximately 412,924 net acres) of Nova Scotia oil and natural gas leases in the Windsor Sub-Basin of the Maritimes Basin. The leases are to expire in 2019, but can be extended pending agreement of further development plans with the Nova Scotia regulators. As of January 31, 2012, we fully impaired and expensed the carrying value of our oil and natural gas leases in the Maritimes Basin.

Results of Operations for the Three Months Ended July 31, 2013 Compared to the Three Months Ended July 31, 2012

For the fiscal quarter ended July 31, 2013, we recorded net income attributable to common stockholders of $6.8 million ($0.12 per share of common stock, basic and diluted) as compared to a net loss attributable to common stockholders of $1.0 million ($0.02 per share of common stock, basic and diluted) for the fiscal quarter ended July 31, 2012. The following discussion highlights the primary drivers of the results within the two periods.


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Oil and Natural Gas Operations



The following table summarizes production volumes, average realized prices, oil
and gas revenues and operating expenses for the three months ended July 31, 2013
and 2012:



                                                                                  Change
                                      Three Months Ended July 31,         Increase      % Increase
                                         2013              2012          (Decrease)     (Decrease)
Production volumes:
Crude oil (Bbls)                            378,107           93,730         284,377           303 %
Natural gas (Mcf)                            82,425           60,226          22,199            37 %
Natural gas liquids (Gallons)               107,528           37,460          70,068           187 %
Total barrels of oil equivalent
(Boe)                                       394,405          104,660         289,745           277 %

Average realized prices:
Crude oil ($ per Bbl)               $         90.37    $       77.01    $      13.37            17 %
Natural gas ($ per Mcf)             $          4.60    $        4.20    $       0.40             9 %
Natural gas liquids ($ per
gallon)                             $          0.83    $        0.97    $      (0.14 )         (14 )%
Total average realized price
($ per Boe)                         $         87.83    $       71.73    $      16.10            22 %

Oil and natural gas revenues (in
thousands):
Crude Oil                           $        34,171    $       7,218    $     26,953           373 %
Natural gas                                     379              253             126            50 %
Natural gas liquids                              89               36              53           146 %
Total oil and natural gas
revenues                            $        34,639    $       7,507    $     27,132           361 %

Operating expenses (in
thousands):
Production taxes                    $         3,919    $         837    $      3,082           368 %
Other lease operating expenses                2,830              220           2,610          1186 %
Gathering, transportation and
processing                                       69               10              59           590 %
Oil and natural gas amortization
expense                                      10,100            2,928           7,172           245 %
Accretion of asset retirement
obligations                                       9                3               6           208 %
Total operating expenses            $        16,927    $       3,998    $     12,929           323 %

Operating expenses per boe:
Production taxes                    $          9.94    $        8.00    $       1.94            24 %
Other lease operating expense       $          7.18    $        2.10    $       5.07           241 %
Gathering, transportation and
processing                          $          0.17    $        0.10    $       0.08            83 %
Oil and natural gas amortization
expense                             $         25.61    $       27.98    $      (2.37 )          (8 )%

Oil and Natural Gas Revenues

Revenues from oil and natural gas production for the three months ended July 31, 2013 increased 361% to $34.6 million from $7.5 million for the same period in 2012 primarily due to the significant increase in oil production from new wells (as noted in the Drilling and Completions section of Recent Events above), partially offset by normal production decline. Average realized oil prices increased 17% to $90.37 per barrel from $77.01 per barrel in the same period in 2012. Average realized gas prices increased 9% to $4.60 per Mcf in the second quarter of fiscal year 2014 from $4.20 per Mcf in the same period in 2012.


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Production Taxes

Due primarily to the 361% increase in oil and natural gas revenues for the three months ended July 31, 2013, as compared with the three months ended July 31, 2012, our U.S. production taxes increased approximately 368% to $3.9 million from $0.8 million for the same respective period. With rare exception, North Dakota production tax rates for the past two years were 11.5% of oil revenue and approximately $0.11 per mcf of natural gas. Effective July 1, 2013, the production tax rate for natural gas decreased to $.0833 per mcf.

Lease Operating Expense

Lease operating expense for U.S. operations ("LOE") increased to $7.18 per Boe for the three months ended July 31, 2013 from $2.10 per Boe for the three months ended July 31, 2012. The increase is primarily the result of increased lease operating expenses associated with our operated properties. LOE for our operated properties was $8.22 per Boe for the three months ended July 31, 2013. This amount includes approximately $2.94 per Boe for water disposal costs. LOE for non-operated properties also increased from $3.37 per Boe for the three months ended July 31, 2012 to $5.22 per Boe for the three months ended July 31, 2013. Our second quarter of fiscal year 2014 reported lease operating expense per boe included a $0.61 per Boe benefit due to an over accrual of estimated lease operating expense in the first quarter of fiscal year 2014.

Gathering, Transportation and Processing

Gathering, transportation and processing ("GTP") expenses increased to $0.17 per Boe for the three months ended July 31, 2013 from $0.10 per Boe for the three months ended July 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. 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.

Oil and Natural Gas Amortization

Oil and natural gas amortization expense increased 245% to $10.1 million for the three months ended July 31, 2013 from $2.9 million for the three months ended July 31, 2012. The increase is primarily related to a 277% increase in production in the second quarter of fiscal year 2014 as compared to the second quarter of fiscal year 2013.

Pressure Pumping Services Gross Profit

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. From formation through July 31, 2013, RockPile has been focused on procuring new pressure pumping and complementary equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, establishing third-party customers in the Williston Basin, and securing multiple credit facilities. RockPile's 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.

For the three months ended July 31, 2013, RockPile performed hydraulic fracturing and complementary services for Triangle and three distinct third-party customers. In July 2013, RockPile's capacity was increased by . . .

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