Exhibit 99.1

Summary

This summary highlights selected information contained elsewhere in this offering memorandum. Because it is a summary, it does not contain all of the information that you should consider before investing in our securities. You should read this offering memorandum, including the section entitled “Risk factors” and the financial statements and related notes to those financial statements, before making an investment decision.

Unless the context otherwise requires, references in this offering memorandum to “TUSA,” the “Company,” “we,” “us,” “our,” or “ours” refer to Triangle USA Petroleum Corporation and its subsidiaries. We are a wholly owned subsidiary of Triangle Petroleum Corporation (“TPLM”), a publicly traded company on the NYSE MKT stock exchange (symbol “TPLM”). Our fiscal year end is January 31.

Our company

We are an exploration and production company focused on developing and acquiring unconventional oil and natural gas resources in the Williston Basin of North Dakota and Montana. Our primary focus is to grow our production volumes through the efficient development of our operated Bakken Shale and Three Forks drilling inventory. We lease approximately 135,000 net acres in the Williston Basin, of which approximately 92,000 are located in our focus area in McKenzie and Williams counties, North Dakota, and eastern Roosevelt and Sheridan counties, Montana, which collectively, we refer to as our “Core Acreage.” Our Core Acreage has high oil saturation, is slightly over-pressured, and has the potential for multiple benches. An April 2013 resource assessment update prepared by the USGS, found that the two formations collectively contain an estimated mean of 7.4 billion barrels of undiscovered, technically recoverable oil. We believe the location, size and concentration of our Core Acreage create an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory. For the twelve months ended April 30, 2014, we generated revenues, net income and Adjusted EBITDA of $200.1 million, $46.5 million and $142.0 million, respectively. For a reconciliation of Adjusted EBITDA to net income (loss), see “—Summary condensed consolidated financial data—Reconciliation of Adjusted EBITDA to net income (loss).”

Our management team has a proven track record of identifying, acquiring and executing large, repeatable development drilling programs, and has substantial experience in the Williston Basin. At January 31, 2012, we had non-operated production of 265 Boepd, and we completed our first operated well in May 2012. From May 2012 through June 30, 2014, we completed 66 gross (47.9 net) operated wells, and our average net daily production for June 2014 would have been approximately 11,400 Boepd on an as adjusted basis for the Acquisitions (defined below). The growth is facilitated by the use of pad drilling, which increases efficiencies while controlling costs and minimizing environmental impact. We also use advanced completion, collection and production techniques designed to optimize reservoir production while reducing costs.

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The following table presents summary data for (i) our proved reserves as of January 31, 2014, (ii) our proved reserves added during the three months ended April 30, 2014, and (iii) proved reserves added upon closing the Acquisitions:

(1)                                 Proved reserves were calculated using prices $93.12 per Bbl for oil, $44.10 per barrel for natural gas liquids, and $4.01 per Mcf for natural gas, which represent the unweighted average of the first-day- of-the-month prices for each of the twelve months ending January 31, 2014, as adjusted for regional price differentials and other factors from benchmark prices of $97.49 per Bbl for oil, $54.25 per barrel for natural gas liquids, and $3.73 per MMbtu for natural gas.

(2)                                 Estimates were prepared by our in-house reservoir engineer and have not been independently audited and are subject to change.

(3)                                 Proved reserves were calculated using a price of $92.50/Bbl for oil, $46.41/Bbl and $5.32/MMBtu for natural gas, which represent the unweighted average of the first-day-of-the-month prices for each of the twelve months ending April 30, 2014, as adjusted for regional price differentials and other factors from benchmark prices of $98.68 per Bbl for oil, $56.50 per barrel for natural gas liquids, and $4.12 per MMbtu for natural gas.

(4)                                 PV-10 represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies.

The information presented above is based on our internal evaluation and interpretation of reserve, acreage and other information provided to us in the course of our due diligence with respect to the Acquisitions and has not been independently verified or estimated. While our management believes the above estimates of proved reserves, and the underlying assumptions used in determining the estimates of proved reserves, are reasonable, actual proved reserves attributable to the Acquisitions will be dependent on actual oil and gas prices, production costs, severance and excise taxes, work-over and remedial costs and governmental regulation. The assumptions underlying our estimates of proved reserves attributable to the Acquisitions could be inaccurate, and the actual reserves of the Acquisitions could differ materially from those we anticipate. See “Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves.”

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Based on results to date and the delineation of the Bakken and Three Forks formations throughout much of our acreage, we believe we have 611 remaining gross operated drilling locations, primarily located in McKenzie and Williams counties. These locations are based on 70 economically viable drilling spacing units (“DSUs”) that we believe will give us at least 12 years of drilling inventory. In our Core Acreage, our base case drilling inventory includes six Bakken wells and four Three Forks wells per DSU. Based on preliminary drilling results by us and other operators in our Core Acreage, as well as geological data under evaluation, we believe there may be additional downspacing opportunities that could result in an upside case of up to eight Bakken wells and eight Three Forks wells per DSU. This upside case includes over 1,000 gross operated drilling locations and drilling inventory for at least 20 years.

(1)                                 Operated DSUs in North Dakota have been confirmed through title. In the eastern Montana portion of the Core Acreage, DSUs with greater than 30% working interest are assumed to be operated.

(2)                                 Base Case based upon six Bakken wells and four Three Forks wells per DSU; Upside Case based upon eight Bakken wells and eight Three Forks wells per DSU.

Our business strategies

·                  Operate our properties as a low-cost producer.  We strive to be the low-cost producer in the Williston Basin. By concentrating our assets within our Core Acreage, we can consolidate operating control and achieve operating efficiencies, including benefits from TPLM’s integrated business model. Our development program centers on pad drilling, batch completions and streamlined production facilities, driving down our per well capital and operating costs. Our finding and development (“F&D”) and lease operating expenses for the fiscal year 2014 were $16.80 per Boe and $7.50 per Boe, respectively. We believe these historical cost results are among the lowest of all operators in the Williston Basin. F&D is a non-GAAP financial measure.

·                  Adopt and develop industry best practices.  Our team is focused on enhancing drilling, completion and production techniques to maximize resource recovery. We utilize our non-operated portfolio as a data center for real-time evaluation of basin-wide completion and spacing trends and results. Our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Oasis, Continental, Whiting, Newfield, EOG and Kodiak. Through our exposure to these operators, we implement a “fast-follower” approach by applying and improving upon drilling and completion techniques. As an operator, we employ what we believe are industry-leading pad designs that enable simultaneous operations, resulting in expedited rig release to first production. Additionally, our development program maximizes hydrocarbon capture through technological advances and forward-looking infrastructure design. As of June 30, 2014, 91%

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of our operated wells were tied-in to gas takeaway infrastructure, eliminating flaring and capturing additional revenue streams.

·                  Acquire strategic and complementary assets.  We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects in or near our Core Acreage. We focus on opportunities where we believe our operational efficiency, reservoir management and geological expertise in unconventional oil and gas properties will enhance value and performance. We regularly review acquisition opportunities and pursue acquisitions that meet our strategic targets. We believe that our size provides us with the opportunity to acquire smaller acreage blocks in the Williston Basin that may be less attractive to larger operators. Furthermore, as some small private ventures struggle to secure development funding, we may have additional opportunities for acquisitions at attractive prices. We also pursue targeted trade opportunities that enable us to convert non-operated acreage into operated DSUs.

·                  Maintain a disciplined capital structure and adequate liquidity.  We employ a disciplined capital structure which focuses on targeted debt metrics and maintaining adequate liquidity. We intend to continue using a conservative financial position to allow us to develop our drilling, exploitation and exploration activities while maximizing the present value of our oil-weighted resource potential. We plan to fund our growth with cash flow from operations, liquidity under our revolver, minimal capital contributions from TPLM and access to capital markets over time. As of April 30, 2014, on an as further adjusted basis after giving effect to the Acquisitions, the offering of the notes and the use of the net proceeds as described herein, we would have had $328.0 million of liquidity, consisting of $14.3 million of cash and cash equivalents and $313.7 million of available borrowing capacity under our senior credit facility.

·                  Operate safely and remain environmentally conscious.  We have assembled a strong asset base within the Williston Basin and are committed to maintaining a strong safety platform and a comprehensive environmental management system. As part of this ongoing process, we are constantly evaluating the safest and most environmentally efficient technologies available in the oil and gas industry. These efforts assist us in identifying and addressing potential concerns that could affect the local landscapes in which we operate.

Our competitive strengths

We have the following competitive strengths that we believe will help us to successfully execute our business strategies:

·                  Attractive, long-lived asset base with multi-year drilling inventory.  We have assembled a sizable asset base within the Williston Basin. We currently lease approximately 135,000 net acres in the Williston Basin, approximately 92,000 of which we consider Core Acreage. Our Core Acreage is prospective in the Bakken and Three Forks formations, and 45% of our proved reserves were classified as proved developed as of January 31, 2014. As of June 30, 2014, we have identified 611 potential drilling locations in our Core Acreage, which we believe provides lower risk development opportunities with at least 12 years of drilling inventory.

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·                  Benefits from integrated and efficient development model.  Through TPLM’s vertically integrated business model, TPLM establishes and maintains control of many of our cost centers. We benefit from dedicated completion services provided by RockPile Energy Services, LLC (“RockPile”), a wholly owned subsidiary of TPLM, which provides for greater control over completion schedules, work quality and production facilities planning. We further benefit from gathering, transportation, and processing of produced volumes provided by Caliber Midstream Partners, L.P. (“Caliber”), TPLM’s 32%-owned midstream services joint venture with First Reserve Energy Infrastructure Fund. Our access to Caliber’s pipeline infrastructure improves realized oil prices through scale and increased marketing optionality, and helps remove trucks from pads, lowering operating costs and supporting simultaneous operations. Our relationship with Caliber also enabled early and dedicated access to midstream infrastructure, whereas most operators in the Williston Basin compete for the services of a limited number of midstream providers.

·                  Track record of growth and high degree of operational control.  Our production has grown from 265 Boepd at January 31, 2012, to an average net daily production for June 2014 of approximately 11,400 Boepd on an as adjusted basis for the Acquisitions, implying a compound annual growth rate (“CAGR”) of 374%. Additionally, our production volumes have shifted from entirely non-operated to 85% operated as of April 30, 2014. This operating control allows us to adjust our capital expenditures program based on commodity price outlooks. Our proved reserves have grown from 1.5 MMBoe at January 31, 2012, to 37.6 MMBoe at January 31, 2014, implying a CAGR of 401%. We continue to lower well costs through pad drilling efficiencies, including decreasing spud to total depth times, implementation of improved completion techniques, and our access to Caliber’s pipeline infrastructure. As a result, we are seeing increased well productivity and initial production rates, thereby generating higher returns on invested capital.

·                  Prudent financial management.  We believe we are well capitalized with 56.6% equity capitalization and substantial liquidity of $328.0 million as of April 30, 2014, in each case, on an as further adjusted basis after giving effect to the Acquisitions, the offering of the notes and the use of the net proceeds as described herein. We are committed to maintaining a conservative balance sheet and disciplined capital program. We participate in an ongoing hedging program to manage our exposure to commodity price fluctuations. As of June 30, 2014, we have approximately 5,900 Bopd hedged for calendar year 2014 and approximately 4,900 Bopd hedged for calendar year 2015.

·                  Disciplined and experienced management.  We have assembled an operations team with substantial technical, operational, commercial, land and regulatory oil and gas experience, with key members having an average of 27 years of experience working in the industry. Jonathan Samuels, our President and Chief Executive Officer, joined us in December 2009, and served as our Chief Financial Officer from January 2010 to April 2012, following an earlier career as a member of an energy focused investment management firm. Justin Bliffen serves as our Chief Financial Officer, after having served for two years as our Vice President and Executive Vice President of Finance. Prior to joining us, Mr. Bliffen worked at Goldman, Sachs & Co. where he was a vice president on the Crude Oil Derivatives Portfolio. We believe that we are well-equipped to prudently navigate the many financial and technical challenges faced by a growing energy company.

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Capital expenditures

Our projected fiscal year 2015 capital budget, including the Acquisitions, is $570 million, of which $360 million is allocated to drilling and completion to spud up to an estimated 50 gross operated wells and complete 46 gross operated wells. During the first quarter of fiscal year 2015, we spent approximately $88.1 million on drilling and completions. We anticipate that all of our fiscal year 2015 capital budget will be directed toward the Williston Basin. During the twelve months ended April 30, 2014, our aggregate drilling and completion capital expenditures were approximately $367 million, excluding acquisitions and internal capitalized costs. We expect the average working interest in wells we drill during fiscal year 2015 will be approximately 73%.

The amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, and drilling and acquisition costs.

Recent events

Acquisition of Williston Basin properties

Primary acquisition

On May 14, 2014, we entered into a definitive purchase and sale agreement (the “Primary Acquisition Agreement”) with Marathon Oil Company (“MRO”) pursuant to which we agreed to acquire from MRO (the “Primary Acquisition”) certain oil and gas leaseholds located in Williams County, North Dakota, Sheridan County, Montana, and Roosevelt County, Montana comprising approximately 41,500 net acres and various other related rights, permits, contracts, equipment and other assets. The effective date for the Primary Acquisition is January 1, 2014. On June 30, 2014, the parties closed the Primary Acquisition for $90.5 million in cash, which included a net downward adjustment of $9.5 million for certain pre-closing adjustments. We funded the Primary Acquisition with capital contributions from TPLM, borrowings under the Senior Credit Facility (as defined below), and borrowings under the Second Lien Credit Facility (as defined below). Additional post-closing adjustments may be required.

Upon closing the Primary Acquisition, we added 3.5 MMBoe of proved reserves. With respect to the assets acquired in the Primary Acquisition, for the three months ended March 31, 2014, realized revenue prices from the sale of oil, natural gas, and natural gas liquids was $81.97 per Boe. Production volumes for the same period were 1,049 Boepd, and operating expenses were $29.06 per Boe. For the twelve months ended December 31, 2012 and 2013, realized revenue prices from the sale of oil, natural gas, and natural gas liquids were $79.61 and $85.81 per Boe, respectively. For the same periods, production volumes were 941 and 1,292 Boepd, and operating expenses were $22.19 and $28.71 per Boe, respectively.

The reserve estimates and financial information above are unaudited and have been prepared internally by us based on information provided to us by the sellers of the acquired assets. Although we believe these estimates and financial information to be accurate, the final estimates and financial information may differ and any such differences could be material.

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Accordingly, you should not place undue reliance on these reserve estimates and financial information.

Secondary Acquisition

On May 1, 2014, we entered into a definitive purchase and sale agreement (the “Secondary Acquisition Agreement”) with a third party (the “Seller”) pursuant to which we agreed to acquire from the Seller (the “Secondary Acquisition”) certain oil and gas leaseholds located in Williams County, North Dakota comprising approximately 4,300 net acres and various other related rights, permits, contracts, equipment and other assets. The effective date for the Secondary Acquisition is January 1, 2014. On June 6, 2014, the parties closed the Secondary Acquisition for approximately $29.3 million in cash, which included a net downward adjustment of approximately $0.5 million for certain pre-closing adjustments. We funded the Secondary Acquisition with capital contributions from TPLM and borrowings under the Senior Credit Facility. Additional post-closing adjustments may be required.

Upon closing the Secondary Acquisition, we added 0.8 MMboe of proved reserves. With respect to the assets acquired in the Secondary Acquisition, for the three months ended March 31, 2014, realized revenue prices from the sale of oil, natural gas, and natural gas liquids was $70.12 per Boe. Production volumes for the same period were 201 Boepd, and operating expenses were $32.27 per Boe. For the twelve months ended December 31, 2012 and 2013, realized revenue prices from the sale of oil, natural gas, and natural gas liquids were $79.05 and $83.85 per Boe, respectively. For the same periods, production volumes were 347 and 273 Boepd, and operating expenses were $29.70 and $37.01 per Boe, respectively.

The reserve estimates and financial information above are unaudited and have been prepared internally by us based on information provided to us by the sellers of the acquired assets. Although we believe these estimates and financial information to be accurate, the final estimates and financial information may differ and any such differences could be material. Accordingly, you should not place undue reliance on these reserve estimates and financial information.

The Primary Acquisition and the Secondary Acquisition are collectively referred to in this offering memorandum as the “Acquisitions”.

Second lien credit facility

On June 27, 2014, we entered into a senior secured second lien credit facility (the “Second Lien Credit Facility”) with Wells Fargo Energy Capital, Inc., as administrative agent, for $60.0 million of term debt. We intend to pay down and terminate the Second Lien Credit Facility using a portion of the proceeds from this offering. TUSA may prepay borrowings under the Second Lien Credit Facility without premium or penalty if such prepayment is made prior to the first anniversary of the closing date. See “Use of proceeds” and “Description of certain other indebtedness—Second lien credit facility” for additional information regarding the Second Lien Credit Facility.

Senior credit facility amendments

In May and June 2014, we entered into three amendments to our senior revolving credit facility (as amended, the “Senior Credit Facility”) to, among other things, increase the borrowing base to $355.0 million, add three new lenders to the facility, permit reimbursement of any funds contributed by TPLM to us in connection with closing the Acquisitions and permit

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us to enter into a second lien credit facility. The amendments also caused the borrowing base to increase by an additional $48.0 million upon closing the Acquisitions. See “Description of certain other indebtedness—Senior credit facility” for additional information regarding the Senior Credit Facility.

Organizational structure

Principal executive offices

Our principal executive offices are located at 1200 17th Street, Suite 2600, Denver, CO 80202, and our telephone number is (303) 260- 7125.

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Summary historical financial information

The following table presents summary historical financial information for the periods indicated. The summary statement of operations data as of, and for the years ended, January 31, 2014, 2013 and 2012, are derived from our audited consolidated financial statements included elsewhere herein. The summary statement of operations data as of, and for the three months ended April 30, 2014 and 2013, are derived from our unaudited condensed consolidated financial statements included elsewhere herein. For further information that will help you better understand the summary data, you should read this financial data in conjunction with the “Management’s discussion and analysis of financial condition and results of operations” section of this offering memorandum and our audited consolidated financial statements and related notes and unaudited condensed consolidated financial statements and related notes and other financial information included elsewhere in this offering memorandum. Our historical results of operations are not necessarily indicative of results to be expected for any future periods.

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(1)                                 Adjusted EBITDA is a non-GAAP financial measure. For a reconciliation of Adjusted EBITDA to net income (loss) see below.

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Adjusted EBITDA

Adjusted EBITDA is not a measure of net income as determined by United States generally accepted accounting principles (“GAAP”). Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income before depletion, depreciation and amortization, impairment of oil and natural gas properties, asset retirement obligation accretion expense, gain (loss) on derivative activities, net cash receipts (payments) on settled derivative instruments, premiums (paid) received on options that settled during the period, interest expense and income tax expense.

Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

Reconciliation of adjusted EBITDA to net income (loss)

The following table presents a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income for each of the periods indicated:

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These ratios were computed by dividing earnings by fixed charges. For this purpose, earnings include income from operations before income taxes, adjusted for: fixed charges to the extent they affect current year earnings, amortization of capitalized interest, distributed income of equity investees, and interest capitalized during the year. Fixed charges include interest expensed and capitalized, amortized premiums, discounts and capitalized expenses related to indebtedness, and estimates of interest within rental expenses.

(1)         There were no fixed charges for the year ended January 31, 2012.

(2)         Ratio is less than one; earnings are inadequate to cover fixed charges. The dollar amount of the coverage deficiency was $2.1 million for the three months ended April 30, 2013.

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Summary historical audited reserves

The following table sets forth certain information with respect to our historical oil and gas reserves as of January 31, 2014, 2013, and 2012, and production data for the years ended January 31, 2014, 2013, and 2012, and for the three months ended April 30, 2014 and April 30, 2013. Future exploration, exploitation and development expenditures, as well as future commodity prices and service costs, will affect the volumes attributable to oil and gas reserves.

The Company’s January 31, 2014 reserve information included in this table is based upon an audit of our internal estimates of proved reserves performed by Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), an independent petroleum engineering firm. Prior to January 31, 2014, internal estimates of proved reserves were audited only at the TPLM level, rather than at the Company level and, accordingly, we have presented TPLM’s reserve data for 2013 and 2012 in the table below which differs from the unaudited internal TUSA reserve data included elsewhere herein and in the accompanying TUSA consolidated financial statements. The January 31, 2013 reserve information included in this table is based upon an audit of TPLM’s internal estimates of proved reserves performed by Cawley Gillespie. The January 31, 2012 reserve information included in this table is based upon an audit of TPLM’s internal estimates of proved reserves performed by Ryder Scott Company, L.P. (“Ryder Scott”), an independent petroleum engineering firm. In all instances, the reserve volumes and values were determined using the methods prescribed by the SEC.

(1)         TPLM’s estimates of proved reserves differ from the Company’s estimates of proved reserves due to assumptions about future development costs. Specifically, intercompany eliminations for services provided by RockPile on TUSA operated wells

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result in lower future development costs at the TPLM level. Based on internal estimates prepared by the Company’s in-house reserve engineer, the Company estimates that total net proved reserves for fiscal year 2013 would have been approximately 12.5 MMBoe had they been prepared and audited at the TUSA level. Further, the Company estimates that PV-10 value for fiscal year 2013 reserves would have been approximately $211.4 million if prepared and audited at the TUSA level, and standardized measure would have been approximately $203.1 million.

(2)         The Company believes that there would have been no difference if reserves had been prepared and audited at the TUSA level because intercompany eliminations at TPLM did not occur until fiscal year 2013.

(3)         The PV-10 value and standardized measure calculations were the same in fiscal year 2012 because estimated undiscounted future cash flows were less than tax basis.

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Capitalization

The following table sets forth our cash and cash equivalents and capitalization as of April 30, 2014, on an actual basis, on an as adjusted basis to give effect to the Acquisitions, the Second Lien Credit Facility, $40.0 million of capital contributions from TPLM to TUSA, and the Senior Credit Facility borrowing base of $403.0 million in effect immediately preceding this offering, and on an as further adjusted basis to give effect to the sale of the securities offered hereby and the application of the net proceeds therefrom as described under “Use of proceeds.” The table below should be read in conjunction with, and is qualified in its entirety by reference to, “Use of proceeds,” “Management’s discussion and analysis of financial condition and results of operations,” our audited consolidated financial statements and related notes thereto, our unaudited condensed consolidated financial statements and notes thereto, included elsewhere in this offering memorandum.

(1)         The aggregate purchase price of the Acquisitions was approximately $119.8 million, and the Company incurred transaction related expenses of approximately $1.3 million and Second Lien Credit Facility closing costs of approximately $1.0 million, both in connection therewith.

(2)         Subsequent to April 30, 2014, we borrowed approximately $57.0 million under our Senior Credit Facility. As of June 30, 2014, we had $295.0 million outstanding under our Senior Credit Facility and $108.0 million of borrowing capacity. Upon the issuance of the notes, the borrowing base in effect will be automatically reduced by an amount equal to (i) 25% of (ii) the aggregate proceeds from the issuance of the notes less the amount of such proceeds applied to repay borrowing under the Second Lien Credit Facility. With a $403.0 million borrowing base at June 30, 2014, the borrowing base would be reduced to $330.5 upon the issuance of the notes. As of April 30, 2014, on an as further adjusted basis after giving effect to the Acquisitions, the offering of the notes and the use of the net proceeds as described herein, we would have had $16.8 million outstanding under our Senior Credit Facility and $313.7 million of borrowing capacity.

(3)         Subsequent to April 30, 2014, we borrowed $60.0 million under our Second Lien Credit Facility. As of June 30, 2014, this amount remained outstanding.

(4)         Assumes notes offered hereby are issued at par.

(5)         Subsequent to April 30, 2014, we received capital contributions totaling $40.0 million from TPLM. As discussed in “Use of proceeds”, we intend to repay these contributions in the form of a dividend at closing of this offering (the “Parent Repayment”).

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