CORRESP 1 filename1.htm

 

Torys LLP
1114 Avenue of the Americas, 23rd Floor

 

New York, New York 10036.7703 USA

 

Telephone:

212.880.6000

 

Facsimile:

212.682.0200

 

 

 

www.torys.com

 

February 26, 2016

 

VIA EDGAR

 

Ms. Pamela Long
Assistant Director
Office of Manufacturing and Construction
Securities and Exchange Commission
100 F Street, N.E.
Mail Stop 4631
Washington, DC 20549

 

Re:

Brookfield Business Partners L.P.

 

Amendment No. 2 to Registration Statement on Form F-1

 

Filed February 2, 2016

 

File No. 333-207621

 

 

Dear Ms. Long:

 

On behalf of our client, Brookfield Business Partners L.P. (the “Company”), we are responding to the comments of the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) set forth in its letter of February 17, 2016 (the “Comment Letter”) to Craig Laurie with respect to the Company’s Amendment No. 2 (“Amendment No. 2”) to the Registration Statement on Form F-1 (the “Registration Statement”).

 

On the date hereof, the Company is filing Amendment No. 3 to the Registration Statement (“Amendment No. 3”) incorporating the revisions described herein and includes other changes intended to update, clarify and render more complete the information contained therein. For the convenience of the Staff and to facilitate the Staff’s review of Amendment No. 3, the Company is supplementally providing with this letter four copies of marked pages that indicate the changes from Amendment No. 2 as filed on February 2, 2016.

 

To facilitate the Staff’s review, we have included in this letter the captions and numbered comments from the Comment Letter in bold text and have provided the Company’s responses immediately following each numbered comment. Unless otherwise noted, page references in the text of this letter correspond to the pages in Amendment No. 3. Capitalized terms used herein and not otherwise defined herein shall have the meanings set forth in Amendment No. 3.

 

Registration Statement on Form F-1 as Amended filed February 02, 2016

 

Ownership and Organizational Structure, page 11

 

1.                          Please disclose the number of units of Holding LP that will be Special LP Units and Redemption-Exchange Units held by Brookfield and Managing GP Units held by BBP, either in the diagram or in the context of footnote

 


 

(1) where you have included the new disclosure about distributions to be made by Holding LP to all owners of its partnership interests on a pro rata, per unit basis.

 

Response.

 

The Company has revised the disclosure on pages 12 and 88 to address the Staff’s comment.

 

Transaction Agreements, page 53

 

2.                          In the third full paragraph, please revise disclosure to provide that in the event there is insufficient cash to pay the distribution, your company may elect to issue additional Redemption-Exchange Units in lieu of cash payment.

 

Response.

 

The Company has revised the disclosure on pages 14, 53, 65 and 140 to address the Staff’s comment.

 

Unaudited Pro Forma Financial Statements, page 57

 

Notes to the Unaudited Condensed Combined Carve-Out Pro Forma Financial Statements, page 62

 

3.                          We note in your response to comment 11 in our letter dated January 11, 2016 that you explain the lack of correlation between the figures relating to the Clearwater acquisition provided on page 68 and such figures provided elsewhere on pages F-163 and F-164 is the result of different currencies, U.S. and Canadian dollars, being utilized in such presentations. Please expand your disclosure to clarify the basis for deriving the figures related to the Clearwater acquisition provided on page 68 from such figures presented elsewhere on pages F-163 and 164, e.g. translated from the Standardized Measure of Discounted Future Cash Flows Relating to Proved Oil and Gas Reserves—Unaudited and the Changes in the Standardized Measure of Properties Acquired by Ember Resources Inc., respectively at an average foreign exchange rate of $1.10 CAD$/USD$ for the year ended December 31, 2014.

 

Response.

 

The Company has revised the disclosure on page 68 to address the Staff’s comment.

 

Business, page 70

 

Production and Price History, page 79

 

4.                          We note that in response to comment 12 in our letter dated January 11, 2016 you have expanded the disclosure of production on page 79 to

 


 

additionally present the figure relating to the combined volumes of oil, natural gas and natural gas liquids expressed as barrels of oil equivalent (“BOE”) net of the interests due to others and net of royalties. Please expand your disclosure to additionally provide the figures relating to your production net of the interests due to others and net of royalties by the final product sold of oil, natural gas and natural gas liquids consistent with the production figures shown in the tabular presentation under FASB ASC 932-235-50-5 presented elsewhere on pages 66 through 67 and F-46.

 

Response.

 

The Company has revised the disclosure on page 79 to address the Staff’s comment.

 

Management and our Master Services Agreement, page 130

 

Management Fee, page 132

 

5.                          We note your response to comment 16 in our letter dated January 11, 2016. Please revise to include disclosure similar to the explanation that you provided in your response.

 

Response.

 

The Company has revised the disclosure on page 134 to address the Staff’s comment.

 

Description of the Holding LP Limited Partnership Agreement, page 153

 

Distributions, page 154

 

6.                          We note your response to comment 19 in our letter dated January 11, 2016. Please revise your disclosure to briefly note the types of expenses you cite in your response, and to clarify that “expenses and outlays” do not include any amounts payable to Brookfield or any service provider or affiliate, since those amounts would be paid by Holding LP or its subsidiaries.

 

Response.

 

The Company has revised the disclosure on page 156 to address the Staff’s comment.

 

Issuance of Additional Partnership Interests, page 154

 

7.                          Please disclose how the redemption-exchange mechanism impacts the issuance of additional partnership interests in the Holding LP.

 

Response.

 

The Company respectfully advises the Staff that the redemption-exchange mechanism does not impact the ability of the Holding LP to issue additional partnership interests or any other security of the Holding LP.  As disclosed in the prospectus, the Holding LP may issue additional partnership units, including Managing General Partner Units, Redemption-Exchange Units, new classes of partnership interests and other securities,

 


 

for any partnership purpose, at any time and on such terms and conditions as the Company may determine at its sole discretion without the approval of any limited partners.

 

Consolidated Financial Statements

 

Note 2.  Significant Accounting Policies, page F-10

 

(i) Property Plant and Equipment, page F-12

 

8.                          We note your response to comment 21 in our letter dated January 11, 2016 regarding your inclusion of future development costs in your depletable cost base. Please provide us with an understanding of the specific IFRS guidance you are relying on to support your accounting. In addition, please tell us how you are able to reasonably estimate future development costs for this purpose, given the inherent likelihood of changes to development plans that may be driven by factors beyond your control. It is also unclear to us how you are able to determine the future development costs are sufficiently probable to be included in DD&A calculations.

 

Response.

 

The Company advises the Staff that it accounts for its oil and natural gas properties (the “properties”) that have proved and/or probable reserves under IAS 16, Property, Plant and Equipment (“IAS 16”).  In accordance with IAS 16.7, the cost of an item of property, plant and equipment (“PP&E”) is recognized as an asset when it is probable that the future economic benefits associated with the item will flow to the entity and the cost can be measured reliably.  Under International Financial Reporting Standards (“IFRS”), the term probable is defined as more likely than not and the probability that a transfer of economic benefits will occur is more than 50 per cent.  As noted in the Company’s letter dated February 2, 2016, the Company is using Canadian National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) to determine oil and gas reserve classifications for accounting purposes which are defined as follows:

 

a.              Proved reserves - are those reserves that can be estimated with a high degree of certainty to be recoverable (there must be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves); and

 

b.              Probable reserves - are those additional reserves that are less certain to be recovered than proved reserves (there must be at least a 50 percent probability that the quantities actually recovered will equal or exceed the estimated probable reserves).

 

In accordance with IAS 16.60, the depreciation, depletion and amortization (“DD&A”) method selected by the Company should reflect the pattern in which the asset’s future economic benefits are expected to be consumed by the entity; however, there is no specific guidance under IAS 16 on the actual method that should be used.  As a result, the Company’s policy choice is to deplete its oil and gas properties using the units-of-

 


 

production method over each respective oil and gas property’s economically proved and probable reserves in accordance with IAS 16.62.  The Company believes that this method is most aligned with the estimated useful life of the oil and gas assets and the nature in which these assets are employed.

 

The Company believes that the use of proved and probable reserves to deplete the unamortized capitalized cost base of its oil and gas assets is more aligned with the overall use of these assets based on the expected production obtained from proved and probable reserves.  Additionally, this assessment is consistent with the underlying economic value of the oil and gas properties which is derived from a fair value model that incorporates both proved and probable reserves.

 

Further, the inclusion of probable reserves within the depletion base of oil and gas assets is supported under paragraph 4.41 of the Conceptual Framework of Financial Reporting within IFRS due to management having a strong knowledge of, and confidence in, the reserves, the long history of reserves and the historical experience of converting probable reserves into proved reserves and ultimately into proved developed producing reserves.

 

In addition, in determining the depletion approach, it is common practice within the Canadian oil and gas industry under IFRS to include proved and probable reserves in estimating the useful life of oil and gas properties and is documented in several industry publications. Notably, the Canadian Association of Petroleum Engineers (“CAPP”) provided the following guidance upon adoption of IFRS in Canada within their publication entitled Information Guide on Adoption and Implementation Guide of International Financial Reporting Standards for the Canadian Upstream Oil and Gas Industry (page 24):

 

“There is no direct guidance under IAS 16 on the reserve categories (e.g., proved (1P) or proved plus probable (2P)) and the pricing method (e.g., constant or forecast (future) pricing) to be used in DD&A calculations. Until guidance is issued by the IASB, an entity is permitted choices in these matters, provided the choices reflect management’s best estimates of the recoverable reserves expected to be obtained from the asset and the choices are applied consistently from period to period.

 

With reference to the principle that the DD&A methodology should reflect the pattern in which the future economic benefits of the assets are expected to be consumed, if an entity following IFRS has elected to deplete its oil and gas reserves using proved and probable reserves, then in order to ensure comparability, the depletion base (i.e., the costs to be depleted) should include the future development costs required to access both classifications of reserves.”

 

The view presented by the CAPP has become widely accepted amongst Canadian oil and gas companies and is supported by the Chartered Professional Accountants of Canada (“CPA Canada”), who have issued several publications on this matter, including the publication entitled Viewpoints: Applying IFRS in the Oil and Gas Industry — Significant IFRS Application Issues (page 4):

 

“The useful life of the oil and natural gas property may be estimated using either proved reserves (1P) or proved and probable reserves (2P). If 2P are used, it is

 


 

important to keep in mind that the depletable amount would include expected future development costs related to undeveloped reserves.

 

IAS 16 Property, Plant and Equipment requires that each part of an item of property, plant and equipment (PPE) with a cost that is significant in relation to the total cost of the item be depreciated separately. In the context of an oil and natural gas property, this means that depletion would be determined on a smaller basis (e.g., on a field-by-field basis or area-by-area basis rather than country-by-country basis).”

 

Consistent with the guidance noted above, proved and probable reserves are included in estimated recoverable reserves for purposes of depleting capitalized oil and gas assets under the units-of-production method and are determined by reference to the Company’s NI 51-101 reserve reports which are updated on an annual basis.  Under NI 51-101, the Company has reserve reports prepared by third party independent engineering firms (GLJ Petroleum Consultants and McDaniel & Associates).  These reserve reports must be filed with the Company’s financial statements as part of its Canadian securities filing requirements under NI 51-101.

 

As the Company has elected to deplete its oil and gas properties using the units-of-production method using estimated proved and probable reserves, to ensure comparability and consistency in the DD&A calculation the depletable cost base must also include future development costs.  As such, the Company has determined that all capital costs incurred to date (which would be reflected in carrying value of the assets in the financial statements) and those capital costs expected to be incurred in the future on the Company’s oil and gas proved and probable reserves (future development costs) should be included in the DD&A calculation. The inclusion of future development costs for both proved and probable reserves within DD&A is consistent with the underlying principle that the costs included in the numerator should reflect all the expenditures necessary for the items included in the denominator.  This concept is provided under US GAAP in Article 4-10 of Regulation S-X that under the full cost method requires the inclusion of estimated future development costs for proved undeveloped reserves and noted as follows:

 

“Amortization of capitalized costs. Capitalized costs within a cost center shall be amortized on the unit-of-production basis using proved oil and gas reserves, as follows:…

 

(i) Costs to be amortized shall include (A) all capitalized costs, less accumulated amortization, other than the cost of properties described in paragraph (ii) below; (B) the estimated future expenditures (based on current costs) to be incurred in developing proved reserves; and (C) estimated dismantlement and abandonment costs, net of estimated salvage values. SX 210.4-10, paragraph (c)(3)(i)”

 

As part of the process, the Company recognizes that it is paramount to make reasonable estimates of proved and probable reserves and the associated future development costs and the Company recognizes the importance of reliable and reasonable estimates of future development costs included in DD&A calculations.  The Company confirms that it undertakes a rigorous process to obtain information with sufficient history, accuracy and reliability to estimate proved and probable reserves and associated future development costs in accordance with the requirements of NI 51-

 


 

101 and the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”).

 

Future development costs are determined initially internally by key personnel with significant oil and gas experience in geology, geophysics, finance, production engineering and reservoir engineering.  These technical personnel determine the estimated reserves and associated costs, both operating and capital, to realize the proved and probable estimates of reserves.  In addition, as part of the work performed by the third party engineers in assigning proved undeveloped and probable additional reserves volumes, they verify the reasonableness of the assumptions and capital costs associated with the determination of those reserves. The future development costs are based on estimates (usually experienced) and may vary based on geography, geology, depth and complexity. Future development costs include estimates for the costs of drilling, completing (fracking) and tie in to pipelines and well facilities of the proved undeveloped and probable additional reserves. The estimates consider many factors, including past company experience and actual costs, expected future costs and comparable well costs by industry peers.

 

The Company confirms that it has a reasonable basis to estimate future development costs and the inclusion of proved and probable reserves under the units-of-production method is supported under IFRS.

 

To further clarify the Company’s accounting policies for its oil and gas operations and to highlight the measurement uncertainties attributable to proved and probable reserves and future development costs, the Company has revised the disclosure on pages F-19 and F-29.

 

9.                          Please refer to paragraphs 122 and 125 of IAS 1 and disclose the judgments and uncertainties, as well as the assumptions you have made regarding the future, pertaining to your oil and gas reserve estimation.

 

Response.

 

The Company has revised the disclosure on page F-19 to address the Staff’s comment.  In addition, the Company has revised the disclosure on page F-29 to disclose the amount of future development costs included in DD&A calculations.

 

Note 3.  Acquisition of Businesses, page F-57

 

10.                   We note your responses to comments 6 and 28 in our letter dated January 11, 2016, as well as the additional disclosures you provided regarding certain entities being “acquired in partnership with institutional investors”. Please revise your disclosures here and in the pro forma financial statements to clarify and disclose your economic interest in each entity you acquire. In addition, please disclose and more fully explain to us how you determined you control each entity in light of your economic interests.

 

Response.

 

The Company has revised the disclosure on pages 62, F-59 and F-60 to address the

 


 

Staff’s comment.

 

The Company also advises the Staff that for purposes of determining control of the relevant acquired entity, the Company considered the guidance under IFRS 10, Consolidated Financial Statements, paragraph 6, and specifically evaluated whether it had power over such acquired entities and an ability to use its power to affect the returns of such entities. The Company notes that through contractual arrangements the Company has a 100% voting interest in the acquired entities identified on pages 62, F-59, and F-60, thereby giving the Company the power to direct all relevant activities of such acquired entities and thereby affect the returns generated by such entities. Therefore, the Company has control over these entities and has concluded that it is appropriate to consolidate these entities under IFRS 10.

 

Yours truly,

 

 

 

 

 

/s/ Mile T. Kurta

 

 

 

 

 

Mile T. Kurta

 

 

 

 

 

Enclosure

 

 

cc:

Chris Ronne

 

Kevin Stertzel

 

Anne McConnell

 

(Securities and Exchange Commission)

 

Craig Laurie

 

(Brookfield Business Partners Limited)