Filed pursuant to Rule 424(b)(3)
Registration Statement No. 333-216891
Prospectus Supplement No. 9
(To Prospectus dated May 17, 2017)
ENERGY RESOURCES 12, L.P.
An Offering of Common Units of Limited Partnership Interest
Minimum Offering: 1,315,790 Common Units
Maximum Offering: 17,631,579 Common Units
This Prospectus Supplement No. 9 supplements and amends the prospectus dated May 17, 2017, referred to herein as the Prospectus. Prospective investors should carefully review the Prospectus and this Prospectus Supplement No. 9 (which is cumulative and replaces all prior supplements).
This prospectus supplement is qualified by reference to the Prospectus, except to the extent that the information in this Prospectus Supplement No. 9 updates or supersedes the information contained in the Prospectus, including any supplements and amendments thereto. This Prospectus Supplement No. 9 is not complete without, and may not be delivered or utilized except in connection with, the Prospectus.
You should rely only on the information contained in this Supplement and the Prospectus. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer to sell these securities in any jurisdiction where offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this Supplement. Our business, financial condition, results of operations and prospects may have changed since that date.
There are significant risks associated with an investment in our common units. These risks are described under the caption “Risk Factors” beginning on page 17 of the Prospectus, as updated on page S-5 in this Prospectus Supplement No. 9.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this Prospectus Supplement No. 9 or the accompanying Prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
The date of this prospectus supplement is September 10, 2018.
TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS | S-1 |
PROSPECTUS SUMMARY UPDATE | S-2 |
The Partnership | S-2 |
Status of the Offering | S-2 |
RECENT DEVELOPMENTS | S-2 |
RISK FACTORS | S-5 |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | S-7 |
EXPERTS | S-12 |
| INFORMATION INCORPORATED BY REFERENCE | S-13 |
INDEX TO FINANCIAL STATEMENTS | S-14 |
FORWARD-LOOKING STATEMENTS
Certain statements within the Prospectus and this Supplement, including the sections entitled “Prospectus Summary,” “Risk Factors,” “Investment Objectives” and “Proposed Activities,” may constitute forward-looking statements. Forward-looking statements are those that do not relate solely to historical fact. They include, but are not limited to, any statement that may predict, forecast, indicate or imply future results, performance, achievements or events. You can identify these statements by the use of words such as “may,” “will,��� “could,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “predict,” “continue,” “further,” “seek,” “plan” or “project” and variations of these words or comparable words or phrases of similar meaning.
These forward-looking statements include such things as:
● | investment objectives and our ability to make investments in a timely manner on acceptable terms; |
● | references to future success in the Partnership’s proposed property acquisition activities; |
● | the types of properties the Partnership may acquire; |
● | our use of proceeds of the offering and our business strategy; |
● | estimated future capital expenditures; |
● | the amount of cash distributions made by the Partnership; |
● | sales of the Partnership’s properties and other liquidity events; |
● | competitive strengths and goals; and |
● | other similar matters. |
These forward-looking statements reflect our current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside our control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under “Risk Factors” and the following:
● | that our strategy of acquiring non-operated oil and gas properties on attractive terms may not be successful or that operations on such properties may not be successful; |
● | general economic, market, or business conditions; |
● | changes in laws or regulations; |
● | the risk that the wells in which we acquire an interest are productive, but do not produce enough revenue to return the investment made; |
● | the risk that the wells drilled on the properties we acquire do not find hydrocarbons in commercial quantities or, even if commercial quantities are encountered, that actual production is lower than expected or the productive life of wells is shorter than expected; |
● | current credit market conditions and our ability to obtain long-term financing for our property acquisitions and drilling activities in a timely manner and on terms that are consistent with what we project when we invest in a property; |
● | uncertainties concerning the price of oil and natural gas, which may decrease and remain low for prolonged periods; and |
● | the risk that any hedging policy we employ to reduce the effects of changes in the prices of our production will not be effective. |
Although we believe the expectations reflected in such forward-looking statements are based upon reasonable assumptions, we cannot assure investors that our expectations will be attained or that any deviations will not be material. Investors are cautioned that forward-looking statements speak only as of the date they are made and that, except as required by law, we undertake no obligation to update these forward-looking statements to reflect any future events or circumstances. All subsequent written or oral forward-looking statements attributable to the Partnership or to individuals acting on its behalf are expressly qualified in their entirety by this section.
PROSPECTUS SUMMARY UPDATE
The Partnership
We are a Delaware limited partnership formed to acquire primarily oil and gas properties located onshore in the United States that will be operated by third-party operators. Such “non-operated” interests may include interests, leasehold interests, royalty interests, overriding royalty interests, production payments and other interests in producing and non-producing oil and gas properties. Such interests are collectively referred to as “properties” or “oil and gas properties.” The general partner does not have any experience in operating oil and gas properties and consequently has engaged experienced operators to conduct normal oil and gas activities on these properties. The Partnership is responsible for its pro rata share of the expenses incurred by the operator, based upon the fraction of the working interest acquired by the Partnership.
David Lerner Associates, Inc. is the dealer manager for the offering of the common units.
Status of the Offering
As of July 25, 2017, the Partnership completed the sale of the minimum offering of 1,315,790 common units of limited partnership interest and therefore broke escrow (the “Initial Closing”). The Partnership was initially offering 2,631,579 common units at $19.00 per common unit and the remaining 15,000,000 common units at $20.00 per common unit. On October 6, 2017, the Partnership had received subscriptions for all of the common units offered at $19.00 per common unit and, consequently, all common units offered and sold after October 6, 2017 will be at $20.00 per common unit.
On August 30, 2018, the Partnership closed on the issuance of approximately 0.5 million additional common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $10.0 million and proceeds net of selling and marketing expenses of approximately $9.4 million. As of August 30, 2018, the Partnership had completed the sale of a total of approximately 6.1 million common units for total gross proceeds of approximately $118.9 million and proceeds net of selling and marketing expenses of $111.8 million. As of August 30, 2018, 11.6 million common units remain unsold. The Partnership is continuing the offering at $20.00 per common unit in accordance with the Prospectus.
RECENT DEVELOPMENTS
The following disclosure is hereby inserted as a new section following the section entitled “Proposed Activities – Well Operations” on page 65 of the Prospectus.
Oil and Gas Properties Acquisition
On November 21, 2017, Energy Resources 12 Operating Company, LLC (“Buyer”), a wholly-owned subsidiary of the Partnership, entered into a Purchase and Sale Agreement (“Purchase Agreement No. 1”) with Bruin E&P Non-Op Holdings, LLC (“Seller”), for the potential purchase (“Acquisition No. 1”) of Seller’s interest in certain non-operated oil and gas properties and the related rights, which at closing represented an approximate average 3.1% non-operated working interest in approximately 204 existing producing wells, 30 wells in various stages of the drilling and completion process, and additional future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Buyer closed on the purchase of the Bakken Assets on February 1, 2018.
The purchase price for Acquisition No. 1 was $87.5 million, subject to customary adjustments, and was funded by net proceeds from the Partnership’s ongoing public offering, proceeds from the unsecured Term Loan (discussed in “Term Loan” below) and an advance from a member of Energy Resources 12 GP, LLC, the general partner of the Partnership (“General Partner”), of $7.0 million. The advance from a member of the General Partner was repaid in full in May 2018. The advance did not bear interest and the member of the General Partner did not receive any compensation for the advance.
Since closing on Acquisition No. 1, the Partnership participated in the drilling of 55 wells, of which 36 have been completed and 19 wells were in various stages of completion at June 30, 2018. During this period, the Partnership incurred approximately $2.9 million in capital drilling and completion costs. As of June 30, 2018, the Partnership owned an approximate 2.7% non-operated working interest in 240 currently producing wells, 19 wells in various stages of the drilling and completion process, and additional future development locations in the Bakken Assets.
On June 29, 2018, Buyer entered into a Purchase and Sale Agreement (“Purchase Agreement No. 2”) with Seller, for the potential purchase of an additional approximate 2.7% non-operated working interest in the Bakken Assets (“Acquisition No. 2”). On August 31, 2018, the Buyer closed on Acquisition No. 2. With the closing of Acquisition No. 2, the Partnership now owns an approximate average 5.4% non-operated working interest in the Bakken Assets.
The purchase price for Acquisition No. 2 was $82.5 million, subject to customary adjustments, and was funded by net proceeds of the Partnership’s best-efforts offering and proceeds from the Partnership’s $60.0 million revolving credit facility entered into on August 31, 2018 (see description of the revolving credit facility below). In addition to the $82.5 million initial purchase price of Acquisition No. 2, the Partnership anticipates that it may be obligated to invest an additional $110 to $120 million in drilling capital expenditures through 2023 to retain its approximate 5.4% working interest in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements governing the Bakken Assets. Since the Partnership is not the operator of any of the Bakken Assets, it is extremely difficult to predict the levels of future participation in the drilling and completion of new wells and their associated capital expenditures. This makes capital expenditures for drilling and completion projects for 2019 and beyond difficult to forecast and current estimated capital expenditure could be significantly different from amounts actually invested. The Partnership expects to fund capital additions related to the drilling and completion of wells primarily from cash provided by operating activities, proceeds from its best-efforts offering, cash on hand and subject to availability, the Credit Facility (as described below).
Prior to closing on Acquisitions No. 1 and No. 2, the Partnership owned no oil and natural gas assets.
The Bakken Assets are operated by 14 third-party operators on behalf of the Partnership and other working interest owners, including WPX Energy (NYSE: WPX), Marathon Oil (NYSE: MRO), EOG Resources (NYSE: EOG) and Continental Resources (NYSE: CLR). The Bakken Assets are located in the Bakken Shale formation, including the Antelope, Spotted Horn, Squaw Creek and Reunion Bay fields. The Bakken Shale and its close geologic cousin, the Three Forks Shale, are found in the Williston Basin, centered in North Dakota and are two of the largest oil fields in the U.S. While oil has been produced in North Dakota from the Williston Basin since the 1950s, it is only since 2007 through the application of horizontal drilling and hydraulic fracturing technologies that the Bakken has seen an increase in production activities.
Advisory and Cost Sharing Agreements
In November 2017, the Partnership engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services (“REI Agreement No. 1”), including supporting Buyer through closing and post-closing of Purchase Agreement No. 1. The Partnership paid REI a total of approximately $5.3 million for its advisory and consulting services under REI Agreement No. 1.
In June 2018, the Partnership engaged REI to perform advisory and consulting services (“REI Agreement No. 2”) and support Buyer through closing and post-closing of Purchase Agreement No. 2, including assistance with due diligence related to Acquisition No. 2 and obtaining financing for Acquisition No. 2. The Partnership paid REI a total of approximately $4.1 million for its advisory and consulting services under REI Agreement No. 2. REI is also entitled to a fee of 5% of the gross sales price in the event the Partnership disposes any or all of the Bakken Assets, if surplus funds are available after Payout to the holders of the Partnership’s common units, as defined in this prospectus.
REI is owned by entities that are controlled by Anthony F. Keating, III, Co-Chief Operating Officer of Energy 11 GP, LLC, and Michael J. Mallick, Co-Chief Operating Officer of Energy 11 GP, LLC. Glade M. Knight and David S. McKenney are the Chief Executive Officer and Chief Financial Officer, respectively, of Energy 11 GP, LLC as well as the Chief Executive Officer and Chief Financial Officer, respectively, of the General Partner.
On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11, L.P. (“E11”) (“Cost Sharing Agreement”) to provide the Partnership access to E11’s personnel and administrative resources. The personnel provide accounting, asset management and other day-to-day management support for the Partnership. The shared day-to-day costs are split evenly between the two partnerships and any direct third-party costs will be paid by the party receiving the services. The shared costs are based on actual costs incurred with no mark-up or profit for E11. The agreement may be terminated at any time by either party upon 60 days written notice. As noted above, the officers and members of our General Partner are also officers and members of the general partner of E11.
The descriptions of Purchase Agreement No. 1, REI Agreement No. 1 and Cost Sharing Agreement set forth above are only summaries and are qualified in their entirety by reference to Purchase Agreement No. 1, REI Agreement No. 1 and Cost Sharing Agreement, copies of which were filed as exhibits to Post-Effective Amendment No. 1 to the Partnership’s Registration Statement on Form S-1. Combined Statements of Revenues and Direct Operating Expenses for the working interests acquired in Acquisition No. 1 are included in this Supplement beginning on F-23.
The descriptions of Purchase Agreement No. 2 and REI Agreement No. 2 set forth above are only summaries and are qualified in their entirety by reference to Purchase Agreement No. 2 and REI Agreement No. 2, copies of which were filed as exhibits to the Partnership’s Current Report on Form 8-K dated July 6, 2018 and incorporated herein by reference. Combined Statements of Revenues and Direct Operating Expenses for the working interests acquired in Acquisition No. 2, along with the Partnership’s pro forma financial statements reflecting Acquisitions No. 1 and No. 2 for the year ended December 31, 2017, and the six months ending June 30, 2018 are included in this Supplement beginning on F-29.
The following disclosure supplements the section entitled Borrowing Policy on page 64 of the Prospectus.
Term Loan
On January 16, 2018, the Partnership, as the borrower, entered into a loan agreement (the “Term Loan Agreement”) with Bank of America, N.A. (“BOA”) which provided for an unsecured term loan (the “Term Loan”) of $25 million. The Term Loan bears interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. Interest is payable monthly. The maturity date was January 15, 2019. As discussed below in Revolving Credit Facility, the maturity date was extended to April 15, 2019. At June 30, 2018, the outstanding balance on the Term Loan was $15 million.
The Term Loan proceeds were used to fund the purchase price of Acquisition No. 1 described in “Oil and Gas Properties Acquisition” above. Under the terms of the Term Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. However, as discussed below, prepayments are limited under the terms of the Credit Facility. The Term Loan Agreement contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Messrs. Knight and McKenney, as Chief Executive Officer and Chief Financial Officer of the General Partner, have guaranteed repayment of the Term Loan and did not receive any consideration in exchange for providing this guarantee.
The description of the Term Loan Agreement set forth above is only a summary and qualified in its entirety by reference to the Term Loan Agreement, a copy of which is filed as an exhibit to Post-Effective amendment No.1 to the Partnership’s Registration Statement on Form S-1.
Revolving Credit Facility
On August 31, 2018, the Partnership and Buyer, as the borrowers, entered into a loan agreement (“Loan Agreement”) with Simmons Bank as administrative agent and the lenders party thereto (collectively, the “Lender”), which provides for a revolving credit facility (the “Credit Facility”) with an initial commitment amount of $60 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The commitment amount may be increased up to $100 million with Lender approval. At closing, the Partnership paid an origination fee of 0.50% of the Revolver Commitment Amount, or $300,000, and is subject to additional origination fees of 0.50% for any increase to the commitment made in excess of the Revolver Commitment Amount. The Partnership is also required to pay an unused facility fee at an annual rate of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter. The maturity date is August 31, 2021 (“Maturity Date”).
Under the Loan Agreement, the initial borrowing base is $60 million. However, the borrowing base is subject to redetermination semi-annually based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. Outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Revolver Commitment Amount at any time. The interest rate, subject to certain exceptions, is equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.75% to 3.75%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Loan Agreement. In addition to monthly interest payments on the outstanding principal balance of the note, the Partnership (subject to certain exceptions) must make mandatory principal payments monthly in an amount equal to 100% of the net proceeds the Partnership receives from the sale of its equity securities until the principal
amount of the note is reduced to $40 million. The Partnership is required to reduce the outstanding principal amount of the note to at or below $40 million by March 15, 2019.
The Loan Agreement also requires the Partnership to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production. The program must cover at least 80% of the Partnership’s total monthly production of oil and natural gas through March 31, 2019, and from April 1, 2019 to the Maturity Date, the program must cover at least 50% of the Partnership’s total monthly oil and natural gas production.
At closing, the Partnership borrowed $60.0 million. The proceeds were used to fund the purchase of Acquisition No. 2 described above and to pay closing costs. Subject to availability, the Credit Facility may also provide additional liquidity for future capital investments, including the drilling and completion of proposed wells by the operators of the Partnership’s properties, and other corporate working capital requirements.
Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.
The Credit Facility contains mandatory prepayment requirements (including those described above), customary affirmative and negative covenants and events of default. The financial covenants as defined in the Loan Agreement include:
| ● | a maximum leverage ratio |
| ● | a minimum current ratio |
| ● | maximum distributions |
As a condition to closing on the Credit Facility, the Partnership was required to extend the maturity of its outstanding Term Loan with BOA to April 15, 2019 from its original maturity date of January 15, 2019. Also, BOA was required to consent to the Partnership entering into the Credit Facility. The Partnership and BOA amended the Term Loan (“BOA Term Loan Amendment”) on August 16, 2018, whereby BOA gave consent and extended the maturity date to April 15, 2019. Under the Credit Facility, no principal payments can be made on the Term Loan until the outstanding balance on the Credit Facility is less than $40.0 million.
The descriptions of the Loan Agreement and the BOA Term Loan Amendment set forth above are only summaries and are qualified in their entirety by reference to the Loan Agreement and the BOA Term Loan Amendment, copies of which were filed as exhibits to the Partnership’s Current Report on Form 8-K dated September 5, 2018.
The following disclosure is added to the end of the section titled “Risk Factors” on page 42 of the Prospectus.
RISK FACTORS
The financial information included herein regarding the Bakken Assets may not represent the financial results of the Bakken Assets for subsequent periods.
In accordance with the rules of the SEC, we have included herein financial information for Acquisition No. 1 for the year ended December 31, 2016 and for the nine months ended September 30, 2017, along with financial information for Acquisition No. 2 for the years ended December 31, 2017 and 2016, and for the six months ended June 30, 2018. During the 30-month period ending June 30, 2018, the average NYMEX oil price was approximately $50.84 per barrel. Reserves included herein at December 31, 2017 and 2016 were determined by applying average prices of crude oil and natural gas for the last 12 months from the applicable date to estimated future production. During the second quarter of 2018, the average NYMEX oil price was approximately $67.91 per barrel. While financial information regarding the past performance of a business is not a guaranteed indication of future performance, given the great disparity in current oil prices between the date of closing on the Bakken Assets and the time frame from which financial information regarding those assets is actually available, investors should understand that in the current pricing environment, past financial performance is less an indication of future financial performance than is usual.
We will need additional funding in order to retain our full interest in the Bakken Assets.
In addition to the $87.5 million initial purchase price for Acquisition No. 1, the $82.5 initial purchase price for Acquisition No. 2 and capital expenditures incurred since such acquisitions, we anticipate that we may be obligated to invest an additional $110 to $120 million in drilling capital expenditures through 2023 to retain our 5.4% working interest in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements governing those properties. We will depend, at least in part, on continued sales pursuant to the terms of this offering and may require additional financing to fund the anticipated capital expenditures needed to retain our full interest in these assets. None of these funding sources is guaranteed, and if we are unable to obtain all of this funding we may lose all or a portion of the assets acquired, and our results of operations will be negatively affected accordingly.
We will have limited control over the activities on properties we do not operate.
Fourteen other companies operate the properties we have acquired. We will have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operators and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
We incurred significant financing indebtedness in connection with our Bakken Assets acquisitions. The financing instruments governing this indebtedness contain restrictions that could adversely affect our operations, our ability to make acquisitions, capital expenditures and our ability to pay distributions to our unitholders.
The borrowing base under the Loan Agreement is subject to redetermination semi-annually based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. Outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Revolver Commitment Amount at any time. In addition to monthly interest payments on the outstanding principal balance of the note, the Partnership must make mandatory principal payments monthly in an amount equal to 100% of the net proceeds the Partnership receives from the sale of its equity securities until the principal amount of the note is reduced to $40 million. The Partnership is required to reduce the outstanding principal amount of the note to at or below $40 million by March 15, 2019. We can make no assurances that we will be successful receiving sufficient proceeds of future sales of our common units in our ongoing best-efforts offering.
The Loan Agreement also requires the Partnership to maintain a risk management program that must cover at least 80% of the Partnership’s total monthly production of oil and natural gas through March 31, 2019, and from April 1, 2019 to the Maturity Date, the program must cover at least 50% of the Partnership’s total monthly oil and natural gas production. See “Our hedging transactions will expose us to counterparty credit risk” and “Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect our ability to pay cash distributions to holders of our common units” risk factors as described in the Prospectus.
Because the indebtedness under the Loan Agreement is secured by a mortgage on 90% of our producing Bakken Assets, the Partnership could lose these properties through foreclosure or other proceedings, if it defaults on that indebtedness. If the Partnership defaults under the Loan Agreement, the interest rate under the Loan Agreement will increase and it is possible that the Partnership could become involved in litigation related to matters concerning its indebtedness under the Loan Agreement. Such litigation could result in significant costs.
The dedication of amounts of net proceeds we receive from subsequent sales of our common units to repay the outstanding indebtedness under the Loan Agreement will reduce our cash available to make distributions to our unitholders or other operating investments, until the indebtedness is reduced to below $40 million. In addition, these and other credit arrangements we may enter into may have the effect of restricting our ability to make distributions, obtain additional financing, make capital investments in our producing assets, participate in future development of wells when presented the opportunity by our operators, sell assets, enter into commodity and interest rate derivative contracts and engage in further property acquisitions. Our ability to comply with the terms of the Loan Agreement in the future is uncertain and will be affected by the levels of cash flow from our operations, additional equity raised from sales of our common units, and events
or circumstances beyond our control. Our failure to comply with certain of the requirements of the Loan Agreement could result in an event of default under their terms, which, if such default continues beyond any applicable cure periods, could cause all of our existing indebtedness to be immediately due and payable.
Additionally, defaulting under the loan may damage the Partnership’s reputation as a borrower and may limit its ability to secure financing in the future.
The following disclosure is hereby inserted as a new section following the section entitled “Terms of the Offering—Acceptance of Subscriptions” on page 54 of the Prospectus.
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto, “Forward-Looking Statements,” and “Risk Factors” appearing elsewhere in this Prospectus Supplement No. 9.
Overview
Energy Resources 12, L.P. (the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership is offering common units of limited partner interest (the “common units”) on a best-efforts basis with the intention of raising up to $350,000,001 of capital, consisting of 17,631,579 common units. The Partnership’s Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and Exchange Commission on May 17, 2017. As of July 25, 2017, the Partnership completed the sale of the minimum offering of common units for gross proceeds of approximately $25 million. Additionally upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990 and Energy Resources 12 GP, LLC (the “General Partner”) received Incentive Distribution Rights (defined below). As of June 30, 2018, the Partnership had completed the sale of 5.2 million common units for gross proceeds of approximately $100.5 million and proceeds net of offering costs of approximately $93.9 million.
The Partnership has no officers, directors or employees. Instead, the General Partner manages the day-to-day affairs of the Partnership. All decisions regarding the management of the Partnership made by the General Partner are made by the Board of Directors of the General Partner and its officers.
The Partnership was formed to acquire primarily oil and gas properties located onshore in the United States. The Partnership seeks to acquire working and other interests in producing and non-producing oil and natural gas properties in the United States and utilize third-party operators to manage the day-to-day operations of such properties.
Oil and Gas Properties Acquisition
On February 1, 2018, the Partnership completed its purchase of an approximate average 3.1% non-operated working interest in 204 producing wells and 30 wells in various stages of the drilling and completion process, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”) for $87.5 million. Prior to this acquisition, the Partnership owned no oil and natural gas assets. The Bakken Assets are operated by 14 third-party operators, including WPX Energy (NYSE: WPX), Marathon Oil (NYSE: MRO), EOG Resources (NYSE: EOG) and Continental Resources (NYSE: CLR). The Bakken Assets are located in the Bakken Shale formation, including the Antelope, Spotted Horn, Squaw Creek and Reunion Bay fields. The Bakken Shale and its close geologic cousin, the Three Forks Shale, are found in the Williston Basin, centered in North Dakota and are two of the largest oil fields in the U.S. While oil has been produced in North Dakota from the Williston Basin since the 1950s, it is only since 2007 through the application of horizontal drilling and hydraulic fracturing technologies that the Bakken has seen an increase in production activities.
The purchase price was funded by net proceeds from the Partnership’s ongoing public offering, proceeds from an unsecured term loan of $25.0 million (discussed in Liquidity and Capital Resources: Financing below) and an advance from a member of the General Partner of $7.0 million. The advance from a member of the General Partner was paid in full in May 2018. The advance did not bear interest and the member of the General Partner did not receive any compensation for the advance.
The purchase price for the Bakken Assets was $87.5 million, subject to customary post-closing adjustments. The Partnership adjusted the purchase price to reflect the operating revenues and expenses of the Bakken Assets between the acquisition effective date of September 1, 2017 and the closing date of February 1, 2018, in accordance with the closing conditions set forth in the purchase agreement. The net impact of the purchase price adjustments was a decrease to the purchase price of the asset of approximately $2.3 million.
From February 1, 2018 to June 30, 2018, the Partnership’s capital drilling costs incurred were approximately $2.9 million for the period for the Partnership’s participation in the drilling and completion of 55 wells, of which 36 have been completed as of June 30, 2018. The Partnership anticipates incurring an additional $0.7 million to complete the 19 wells in various stages of completion. The Partnership anticipates that it may be obligated to invest approximately $7 to $9 million in drilling and completion capital expenditures for the remainder of 2018 for additional planned drilling by its operators, and a total of approximately $55 to $60 million in drilling and completion capital expenditures through 2023 to fully participate in operator drilling programs in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements governing the Bakken Assets. Since the Partnership is not the operator of any of the Bakken Assets described, it is extremely difficult to predict the levels of future participation in the drilling and completion of new wells and their associated capital expenditures. This makes capital expenditures for drilling and completion projects for 2019 and beyond difficult to forecast and current estimated capital expenditure could be significantly different from amounts actually invested. The Partnership expects to fund capital additions related to the drilling and completion of wells primarily from cash provided by operating activities, proceeds from its best-efforts offering and cash on hand.
Potential Acquisition as of June 30, 2018
On June 29, 2018, the Partnership, through a wholly-owned subsidiary (the “Buyer”) entered into a Purchase and Sale Agreement (“Purchase Agreement No. 2”) with Bruin E&P Non-Op Holdings, LLC (“Seller”), for the potential purchase of an additional portion of the Seller’s interest in the Bakken Assets, resulting in the Partnership acquiring an additional approximate average 2.7% non-operated working interest (the “Target Assets”), so if all conditions to closing on the Target Assets are met under the Purchase Agreement No. 2, the Partnership’s non-operated working interest in the Bakken Assets would increase to approximately 5.4%. The acquisition was completed on August 31, 2018.
Pursuant to Purchase Agreement No. 2, the purchase price for the Target Assets is $82.5 million, subject to customary adjustments. On June 29, 2018, the Partnership funded a deposit of 5% of the purchase price, or $4,125,000 (the “Deposit”), to the Seller to be applied toward the purchase price at closing or to be released to the Seller if the transaction does not close by the outside closing date due to the Buyer’s breach of Purchase Agreement No. 2. In the event the transaction does not close due to a breach by Sellers, the Deposit will be refunded to the Partnership. If the Buyer does not perform under the contract as a result of its diligence review or otherwise breach Purchase Agreement No. 2, the Sellers’ sole remedy against the Buyer is release of the Deposit to the Seller. The final settlement purchase price is subject to the customary post-closing adjustments, as defined and identified in Purchase Agreement No. 2.
The closing of Purchase Agreement No. 2 is subject to the satisfaction of a number of required conditions which currently remain unsatisfied under Purchase Agreement No. 2. Consummation of the acquisition is subject to the Buyer’s satisfactory completion of the review of title, environmental investigations, financial analysis and geological analysis, obtaining sufficient financing to fund the purchase price and other due diligence. Accordingly, there can be no assurance at this time that all of the conditions precedent to consummating Purchase Agreement No. 2 will be satisfied, that the Partnership will find the results of its diligence investigation acceptable, that the Partnership will be able to obtain sufficient financing on terms reasonably acceptable or that the transaction will be successfully completed.
The Partnership has engaged REI (see Note 3. Oil and Gas Investments to the Partnership’s June 30, 2018 financial statements included herein for discussion of REI) to perform advisory and consulting services and support the Partnership through closing of Purchase Agreement No. 2, including assistance with due diligence related to the Target Assets and obtaining financing for the proposed transaction. The Partnership will pay REI a total of approximately $4.1 million for its advisory and consulting services. REI is also entitled to a fee of 5% of the gross sales price in the event the Partnership disposes any or all of the Target Assets, if surplus funds are available after Payout to the holders of the Partnership’s common units, as defined below.
Current Price Environment
Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Due to global supply and demand concerns as well as ongoing geopolitical risks in oil producing regions of the world, energy commodity prices are historically volatile and may continue into the future. The average daily NYMEX prices for oil and natural gas for the three months ended June 30, 2018 were $67.91 per barrel of oil and $2.85 per Mcf of natural gas, respectively. The average daily NYMEX prices for oil and natural gas from February 1, 2018 to June 30, 2018 were $65.83 per barrel of oil and $2.79 per Mcf of natural gas, respectively.
Results of Operations
The Partnership closed on its purchase of the Bakken Assets on February 1, 2018. Other than the payment of fees and expenses described herein, the Partnership had no other operations prior to the acquisition of the Bakken Assets. Because the Partnership had no revenues in fiscal 2017, there is no comparison of the Partnership’s results of operations for the three and six months ended June 30, 2018 to the Partnership’s results of operations for the three and six months ended June 30, 2017, except as otherwise indicated below.
In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly production in barrel of oil equivalent (“BOE”) units, (2) average sales price per unit for oil, natural gas and natural gas liquids and (3) production costs per BOE. The following table is a summary of the results from operations, including production, of the Partnership’s non-operated working interest in the Bakken Assets for the three months ended June 30, 2018 and the five-month period February 1, 2018 to June 30, 2018.
Three Months Ended June 30, | Five Months Ended June 30, | |||||||||||||||
2018 | Percent of Revenue | 2018 | Percent of Revenue | |||||||||||||
Total revenue | $ | 7,531,096 | 100.0 | % | $ | 11,028,175 | 100.0 | % | ||||||||
Production expenses | 1,635,724 | 21.7 | % | 2,268,627 | 20.6 | % | ||||||||||
Production taxes | 617,248 | 8.2 | % | 938,526 | 8.5 | % | ||||||||||
Depreciation, depletion, amortization and accretion | 1,321,361 | 17.5 | % | 2,016,079 | 18.3 | % | ||||||||||
Production (BOE): | ||||||||||||||||
Oil | 106,316 | 162,820 | ||||||||||||||
Natural gas | 18,454 | 23,404 | ||||||||||||||
Natural gas liquids | 14,009 | 21,137 | ||||||||||||||
Total | 138,779 | 207,361 | ||||||||||||||
Average sales price per unit: | ||||||||||||||||
Oil (per Bbl) | $ | 66.02 | $ | 62.69 | ||||||||||||
Natural gas (per Mcf) | 2.64 | 2.67 | ||||||||||||||
Natural gas liquids (per Bbl) | 15.71 | 21.03 | ||||||||||||||
Combined average sales price (per BOE) | 54.27 | 53.18 | ||||||||||||||
Average unit cost per BOE: | ||||||||||||||||
Production expenses | 11.79 | 10.94 | ||||||||||||||
Production taxes | 4.45 | 4.53 | ||||||||||||||
Depreciation, depletion, amortization and accretion | 9.52 | 9.72 | ||||||||||||||
Oil, Natural Gas and NGL Sales
For the three months ended June 30, 2018, revenues for oil, natural gas and NGL sales were $7.5 million. Revenues for the sale of crude oil were $7.0 million, which resulted in a realized price of $66.02 per barrel. Revenues for the sale of natural gas were $0.3 million, which resulted in a realized price of $2.64 per Mcf. Revenues for the sale of NGLs were $0.2 million, which resulted in a realized price of $15.71 per BOE of production.
For the five months from February 1, 2018 to June 30, 2018, revenues for oil, natural gas and NGL sales were $11.0 million. Revenues for the sale of crude oil were $10.2 million, which resulted in a realized price of $62.69 per barrel.
Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $2.67 per Mcf. Revenues for the sale of NGLs were $0.4 million, which resulted in a realized price of $21.03 per BOE of production.
Production Expenses
Production expenses are daily costs incurred by the Partnership to bring oil and natural gas out of the ground and to market, along with the daily costs incurred to maintain producing properties. Such costs include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to the Partnership’s oil and natural gas properties, along with the gathering and processing contracts in effect for the extraction, transportation and treatment of natural gas.
Production expenses for the three months ended June 30, 2018 were $1.6 million, and production expenses per BOE were $11.79. Production expenses for the five months from February 1, 2018 to June 30, 2018 were $2.3 million, and production expenses per BOE were $10.94.
Production Taxes
Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil. Production taxes for the three months ended June 30, 2018 were $0.6 million (8.2% of revenue). Production taxes for the five months from February 1, 2018 to June 30, 2018 were $0.9 million (8.5% of revenue).
Depreciation, Depletion, Amortization and Accretion (“DD&A”)
DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. The Partnership’s DD&A for the three months ended was $1.3 million, and DD&A per BOE of production was $9.52. DD&A for the five months from February 1, 2018 to June 30, 2018 was $2.0 million, and DD&A per BOE of production was $9.72.
General and Administrative Costs
The principal components of general and administrative expense are accounting, legal, advisory and consulting fees. General and administrative costs for the three months ended June 30, 2018 and 2017 were $0.3 million and $14,845, respectively. General and administrative expenses for the six months ended June 30, 2018 and 2017 were $0.7 million and $21,105, respectively. General and administrative expenses for the three and six months ended June 30, 2018 exceeded those of the prior year due to the Partnership raising funds through its ongoing offering and closing on its non-operated working interest in the Bakken Assets in February 2018, resulting in a rise in year-to-date accounting, legal and consulting fees.
Interest Expense
Interest expense, net, for the three months ended June 30, 2018 and 2017 was $0.2 million and $830, respectively. Interest expense, net, for the six months ended June 30, 2018 and 2017 was $0.4 million and $1,105, respectively. The primary component of Interest expense, net, during the three and six months ended June 30, 2018 was interest expense on the Term Loan, as discussed below in Liquidity and Capital Resources: Financing.
Supplemental Non-GAAP Measure
The Partnership uses “EBITDAX”, defined as Earnings before Interest, Income Taxes, Depreciation, Depletion, Amortization and Exploration Expenses, as a key supplemental measure of its operating performance. This non-GAAP financial measure should be considered along with, but not as an alternative to, net income (loss), operating income (loss), cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. EBITDAX is not necessarily indicative of funds available to fund the Partnership’s cash needs, including its ability to make cash distributions. Although EBITDAX, as calculated by the Partnership, may not be comparable to EBITDAX as reported by other companies that do not define such term exactly as the Partnership defines such term, the Partnership believes this
supplemental measure is useful to investors when comparing the Partnership’s results between periods and with other energy companies.
The Partnership believes that the presentation of EBITDAX is important to provide investors with additional information (i) to provide an important supplemental indicator of the operational performance of the Partnership’s business without regard to financing methods and capital structure, and (ii) to measure the operational performance of the Partnership’s operators.
The following table reconciles the Partnership’s GAAP net income to EBITDAX for the three and six months ended June 30, 2018.
Three Months Ended | Six Months Ended | |||||||
Net income | $ | 3,400,535 | $ | 4,688,860 | ||||
Interest expense, net | 212,483 | 372,049 | ||||||
Depreciation, depletion, amortization and accretion | 1,321,361 | 2,016,079 | ||||||
Exploration expenses | - | - | ||||||
EBITDAX | $ | 4,934,379 | $ | 7,076,988 | ||||
Transactions with Related Parties
The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to existing related party transactions, as well as any new significant related party transactions.
See further discussion in “Note 7. Related Parties” to the Partnership’s June 30, 2018 financial statements included herein.
Liquidity and Capital Resources
The Partnership’s principal source of liquidity will be the proceeds of the best-efforts offering and the cash flow generated from properties the Partnership acquired on February 1, 2018. The Partnership anticipates that cash on hand, cash flow from operations, additional financing and proceeds of the best-efforts offering will be adequate to meet its liquidity requirements for at least the next 12 months. If the Partnership is unable to raise sufficient proceeds from its ongoing best-efforts offering or obtain additional financing, it may be unable to complete the potential acquisition of additional non-operated working interests in the Bakken Assets discussed above, pay distributions or participate in the drilling programs discussed above.
Financing
On January 16, 2018, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”) with Bank of America, N.A. (the “Lender”), which provides for an unsecured term loan (the “Term Loan”) of $25 million. The Term Loan bears interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. Interest is payable monthly. The maturity date is January 15, 2019.
The Term Loan proceeds were used in closing on the Partnership’s purchase of the Bakken Assets, as described above. Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. Glade M. Knight and David S. McKenney, the General Partner’s Chief Executive Officer and Chief Financial Officer, respectively, have guaranteed repayment of the Term Loan and did not and will not receive any consideration in exchange for providing this guarantee. The Partnership intends to use proceeds from its best-efforts offering to repay the Term Loan. At June 30, 2018, the outstanding balance on the Term Loan was $15.0 million.
In addition, see “Revolving Credit Facility” on page S-4 for more information on debt assumed by the Partnership in conjunction with the completed acquisition on August 31, 2018.
Partners’ Equity
The Partnership intends to continue to raise capital through its best-efforts offering of common units by the Managing Dealer at $20.00. Under the agreement with the Managing Dealer, the Managing Dealer receives a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through June 30, 2018, the Dealer Manager Incentive Fees are approximately $4.0 million, subject to Payout (defined below). As of June 30, 2018, the Partnership had completed the sale of 5.2 million common units for gross proceeds of approximately $100.5 million and proceeds net of offering costs of approximately $93.9 million.
Distributions
Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.
The Partnership Agreement provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.
All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:
● | First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. |
● | Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. |
All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.
For the three and six months ended June 30, 2018, the Partnership paid distributions of $0.349041 and $0.698082 per common unit, or $1.4 million and $2.6 million, respectively.
Since a portion of distributions to date have been funded with proceeds from the offering of common units, the Partnership’s ability to maintain its current intended rate of distribution will be based on its ability to increase its cash generated from operations. As there can be no assurance that the assets acquired by the Partnership will provide income at this level, there can be no assurance as to the classification or duration of distributions at the current rate. Proceeds of the offering which are distributed are not available for investment in properties.
EXPERTS
The following disclosure is added to the end of the section titled “Experts” on page 108 of the Prospectus.
The consolidated financial statements of Energy Resources 12, L.P. at December 31, 2017 and December 31, 2016 and for the year ended December 31, 2017 and the period from December 30, 2016 (initial capitalization) through December 31, 2016, appearing in this Supplement No. 9 to the Partnership’s Registration Statement on Form S-1, have been audited by
Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.
The combined statements of revenues and direct operating expenses of properties under contract for purchase by a subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC under agreement dated November 21, 2017 for the year ended December 31, 2016 and for the nine months ended September 30, 2017, appearing in this Supplement No. 9 to the Partnership’s Registration Statement on Form S-1, have been audited by Ernst & Young LLP, independent auditor, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.
The combined statements of revenues and direct operating expenses of properties acquired by a subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC under agreement dated June 29, 2018 for the years ended December 31, 2017 and 2016, appearing in this Supplement No. 9 to the Partnership’s Registration Statement on Form S-1, have been audited by Ernst & Young LLP, independent auditor, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.
The following disclosure is hereby inserted as a new section following the section entitled “EXPERTS” on page 108 of the Prospectus.
INFORMATION INCORPORATED BY REFERENCE
The SEC allows us to “incorporate by reference” into this prospectus the information we provide in other documents filed by us with the SEC. The information incorporated by reference is an important part of this prospectus and any prospectus supplement. Any statement contained in a document that is incorporated by reference in this prospectus is automatically updated and superseded if information contained in this prospectus and any prospectus supplement, or information that we later file with the SEC, modifies and replaces this information. We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Periodic Reports on Form 8-K that will be incorporated by reference. We incorporate by reference the documents listed below (unless otherwise stated, other than information furnished under Items 2.02 or 7.01 of any Form 8-K, which is not deemed filed):
• | Annual Report on Form 10-K for the year ended December 31, 2017, filed on February 26, 2018 |
• | Quarterly Report on Form 10-Q for the three months ended March 31, 2018 filed on May 14, 2018 |
• | Quarterly Report on Form 10-Q for the three and six months ended June 30, 2018 filed on August 14, 2018 |
• | Current Report on Form 8-K filed on July 6, 2018 |
• | Current Report on Form 8-K filed on September 5, 2018 |
In addition, all documents filed by us with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act (other than those furnished pursuant to Item 2.02 or Item 7.01 of Form 8-K, unless otherwise stated therein), including all such filings after the effective date of the registration statement of which this prospectus is a part, until all offerings under the registration statement of which this prospectus is a part are completed or terminated, will be considered to be incorporated by reference into this prospectus and to be a part of this prospectus from the dates of the filing of such documents. Pursuant to General Instruction B of Form 8-K, any information submitted under Item 2.02, Results of Operations and Financial Condition, or Item 7.01, Regulation FD Disclosure, of Form 8-K is not deemed to be “filed” for the purpose of Section 18 of the Exchange Act, and we are not subject to the liabilities of Section 18 with respect to information submitted under Item 2.02 or Item 7.01 of Form 8-K. We are not incorporating by reference any information submitted under Item 2.02 or Item 7.01 of Form 8-K into any filing under the Securities Act or the Exchange Act or into this prospectus, unless otherwise indicated on such Form 8-K.
You may get copies of this prospectus or any of the incorporated documents (excluding exhibits, unless the exhibits are specifically incorporated) at no charge to you by writing to the Corporate Secretary, Energy Resources 12, L.P., 814 East Main Street, Richmond, VA 23219, or calling (804) 344-8121. Copies of the incorporated documents will be available on our website at http://www.energyresources12.com. and also at the SEC at the locations described under “Additional Information” in this prospectus.
INDEX TO FINANCIAL STATEMENTS
Page | |
Energy Resources 12, L.P. Historical Consolidated Financial Statements (unaudited): | |
Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017 | F-1 |
Consolidated Statements of Operations for the three and six months ended June 30, 2018 and 2017 | F-2 |
Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017 | F-3 |
Notes to Consolidated Financial Statements | F-4 |
Energy Resources 12, L.P. Historical Consolidated Financial Statements: | |
Report of Independent Registered Public Accounting Firm | F-11 |
Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016 | F-12 |
Consolidated Statements of Operations for the year ended December 31, 2017 and the period ended from December 30, 2016 (initial capitalization) to December 31, 2016 | F-13 |
Consolidated Statements of Partners’ Equity for the year ended December 31, 2017 and the period ended from December 30, 2016 (initial capitalization) to December 31, 2016 | F-14 |
Consolidated Statements of Cash Flows for the year ended December 31, 2017 and the period ended from December 30, 2016 (initial capitalization) to December 31, 2016 | F-15 |
Notes to Consolidated Financial Statements | F-16 |
Combined Statements of Revenues and Direct Operating Expenses of Properties under Contract for Purchase by a Subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings under Agreement dated November 21, 2017: | |
Report of Independent Auditors | F-23 |
Combined Statements of Revenues and Direct Operating Expenses for the year ended December 31, 2016 and the nine months ended September 30, 2017 | F-24 |
Notes to Combined Statements of Revenues and Direct Operating Expenses | F-25 |
Combined Statements of Revenues and Direct Operating Expenses of Properties Acquired by a Subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings under Agreement dated June 29, 2018: | |
Report of Independent Auditors | F-29 |
Combined Statements of Revenues and Direct Operating Expenses for the years ended December 31, 2017 and 2016 and the six months ended June 30, 2018 | F-30 |
Notes to Combined Statements of Revenues and Direct Operating Expenses | F-31 |
Energy Resources 12, L.P. Unaudited Pro Forma Condensed Combined Financial Statements: | |
Introduction | F-35 |
Unaudited Pro Forma Condensed Balance Sheet dated June 30, 2018 | F-37 |
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year ended December 31, 2017 | F-38 |
Unaudited Pro Forma Condensed Combined Statement of Operations for the Six Months ended June 30, 2018 | F-39 |
Notes to Unaudited Pro Forma Condensed Combined Financial Statements | F-40 |
Energy Resources 12, L.P.
Consolidated Balance Sheets
(Unaudited)
June 30, | December 31, | |||||||
2018 | 2017 | |||||||
Assets | ||||||||
Cash and cash equivalents | $ | 11,881,132 | $ | 46,859,728 | ||||
Oil, natural gas and natural gas liquids revenue receivable | 3,881,168 | - | ||||||
Deposit for potential acquisition | 4,125,000 | 8,750,000 | ||||||
Deferred acquisition costs | 4,125,981 | 4,884,208 | ||||||
Total Current Assets | 24,013,281 | 60,493,936 | ||||||
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $2,013,028 and $0, respectively | 91,234,376 | - | ||||||
Total Assets | $ | 115,247,657 | $ | 60,493,936 | ||||
Liabilities | ||||||||
Term loan | $ | 15,000,000 | $ | - | ||||
Due to related parties | 4,474,698 | 5,283,623 | ||||||
Accounts payable and accrued expenses | 1,616,021 | 164,786 | ||||||
Total Current Liabilities | 21,090,719 | 5,448,409 | ||||||
Asset retirement obligations | 141,768 | - | ||||||
Total Liabilities | 21,232,487 | 5,448,409 | ||||||
Partners’ Equity | ||||||||
Limited partners' interest (5,157,398 and 3,191,231 common units issued and outstanding, respectively) | 94,015,385 | 55,045,742 | ||||||
General partner's interest | (215 | ) | (215 | ) | ||||
Total Partners’ Equity | 94,015,170 | 55,045,527 | ||||||
Total Liabilities and Partners’ Equity | $ | 115,247,657 | $ | 60,493,936 | ||||
See notes to consolidated financial statements.
Energy Resources 12, L.P.
Consolidated Statements of Operations
(Unaudited)
Three Months Ended | Three Months Ended | Six Months Ended | Six Months Ended | |||||||||||||
June 30, 2018 | June 30, 2017 | June 30, 2018 | June 30, 2018 | |||||||||||||
Revenue | ||||||||||||||||
Oil, natural gas and natural gas liquids revenues | $ | 7,531,096 | $ | - | $ | 11,028,175 | $ | - | ||||||||
Operating costs and expenses | ||||||||||||||||
Production expenses | 1,635,724 | - | 2,268,627 | - | ||||||||||||
Production taxes | 617,248 | - | 938,526 | - | ||||||||||||
General and administrative expenses | 343,745 | 14,845 | 744,034 | 21,105 | ||||||||||||
Depreciation, depletion, amortization and accretion | 1,321,361 | - | 2,016,079 | - | ||||||||||||
Total operating costs and expenses | 3,918,078 | 14,845 | 5,967,266 | 21,105 | ||||||||||||
Operating income | 3,613,018 | (14,845 | ) | 5,060,909 | (21,105 | ) | ||||||||||
Interest expense, net | (212,483 | ) | (830 | ) | (372,049 | ) | (1,105 | ) | ||||||||
Net income (loss) | $ | 3,400,535 | $ | (15,675 | ) | $ | 4,688,860 | $ | (22,210 | ) | ||||||
Basic and diluted net income per common unit | $ | 0.82 | $ | 1.24 | ||||||||||||
Weighted average common units outstanding - basic and diluted | 4,158,589 | 3,795,001 | ||||||||||||||
See notes to consolidated financial statements.
Energy Resources 12, L.P.
Consolidated Statements of Cash Flows
(Unaudited)
Six Months Ended | Six Months Ended | |||||||
June 30, 2018 | June 30, 2017 | |||||||
Cash flow from operating activities: | ||||||||
Net income (loss) | $ | 4,688,860 | $ | (22,210 | ) | |||
Adjustments to reconcile net income to cash from operating activities: | ||||||||
Depreciation, depletion, amortization and accretion | 2,016,079 | - | ||||||
Changes in operating assets and liabilities: | ||||||||
Oil, natural gas and natural gas liquids revenue receivable | (4,427,059 | ) | - | |||||
Due to related parties | (208,925 | ) | - | |||||
Accounts payable and accrued expenses | 1,069,593 | 18,668 | ||||||
Net cash flow provided by (used in) operating activities | 3,138,548 | (3,542 | ) | |||||
Cash flow from investing activities: | ||||||||
Cash paid for acquisition of oil and natural gas properties | (81,696,819 | ) | - | |||||
Deposit for potential acquisition of oil and natural gas properties | (4,125,000 | ) | - | |||||
Additions to oil and natural gas properties | (1,571,696 | ) | - | |||||
Net cash flow used in investing activities | (87,393,515 | ) | - | |||||
Cash flow from financing activities: | ||||||||
Cash paid for offering costs | - | (224,608 | ) | |||||
Net proceeds from line of credit | - | 229,000 | ||||||
Proceeds from term loan | 25,000,000 | - | ||||||
Payments on term loan | (10,000,000 | ) | - | |||||
Proceeds from advance from member of general partner | 7,000,000 | - | ||||||
Payments on advance from member of general partner | (7,000,000 | ) | - | |||||
Net proceeds related to issuance of units | 36,908,195 | - | ||||||
Distributions paid to limited partners | (2,631,824 | ) | - | |||||
Net cash flow provided by financing activities | 49,276,371 | 4,392 | ||||||
Increase (decrease) in cash and cash equivalents | (34,978,596 | ) | 850 | |||||
Cash and cash equivalents, beginning of period | 46,859,728 | 1,000 | ||||||
Cash and cash equivalents, end of period | $ | 11,881,132 | $ | 1,850 | ||||
Interest paid | $ | 397,954 | $ | 679 | ||||
Supplemental non-cash information: | ||||||||
Accrued deferred offering costs | - | 258,683 | ||||||
See notes to consolidated financial statements.
Energy Resources 12, L.P.
Notes to Consolidated Financial Statements
June 30, 2018
(Unaudited)
Note 1. Partnership Organization
Energy Resources 12, L.P. (together with its wholly-owned subsidiary, the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership is offering common units of limited partner interest (the “common units”) on a best-efforts basis with the intention of raising up to $350,000,001 of capital, consisting of 17,631,579 common units. The Partnership’s offering was declared effective by the Securities and Exchange Commission (“SEC”) on May 17, 2017. As of July 25, 2017, the Partnership completed the sale of the minimum offering of 1,315,790 common units. The subscribers to the common units were admitted as Limited Partners of the Partnership at the initial closing of the offering and the Partnership has been admitting additional Limited Partners monthly since that time.
The Partnership’s primary investment objectives are to (i) acquire producing and non-producing oil and gas properties with development potential to be operated by third-party operators, and to enhance the value of the properties through drilling and other development activities, (ii) make distributions to the holders of the common units, (iii) engage in a liquidity transaction after five to seven years, in which all properties are sold and the sales proceeds are distributed to the partners, merge with another entity, or list the common units on a national securities exchange, and (iv) permit holders of common units to invest in oil and gas properties in a tax efficient basis. The proceeds from the sale of the common units primarily will be used to acquire producing and non-producing oil and natural gas properties onshore in the United States, and to develop those properties.
As of June 30, 2018, the Partnership owned an approximate 2.7% non-operated working interest in 240 currently producing wells and 19 wells in various stages of the drilling and completion process, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 14 third-party operators on behalf of the Partnership and other working interest owners.
The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. David Lerner Associates, Inc. (the “Managing Dealer”), is acting as the dealer manager for the offering of the common units.
The Partnership’s fiscal year ends on December 31.
Note 2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited December 31, 2017 financial statements included in its 2017 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2018.
Cash and Cash Equivalents
Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.
Offering Costs
The Partnership is raising capital through an on-going best-efforts offering of units by the Managing Dealer, which receives a selling commission and a marketing expense allowance based on proceeds of the units sold. Additionally, the Partnership has incurred other offering costs including legal, accounting and reporting services. These offering costs are recorded by the Partnership as a reduction of partners’ equity. As of June 30, 2018, the Partnership had completed the sale of 5.2 million common units for gross proceeds of approximately $100.5 million and proceeds net of offering costs of approximately $93.9 million.
Use of Estimates
The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
The Partnership does not operate its oil and natural gas properties and receives actual oil, natural gas and natural gas liquids (“NGL”) sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. The Partnership closed on its first property acquisition on February 1, 2018 and continues to complete the requisite division and transfer orders to obtain title for each well with each operator. As a result, the operational data received from the operators during the post-close process is preliminary. Therefore, the Partnership has used the most current available production data gathered from its operators and the Oil and Gas Division of the North Dakota Industrial Commission, and oil, natural gas and NGL national index prices are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined or the settlement proceeds are received.
Reclassifications
Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows.
Net Income Per Common Unit
Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and six months ended June 30, 2018. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 6) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 6) would occur.
Revenue Recognition
Since it did not acquire any assets until 2018, the Partnership did not record any revenue in 2017. The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. Settlement receipts for sales of oil, natural gas and natural gas liquids may not be received for more than a month after the date production is delivered to the purchaser, and as a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Partnership records the differences between estimates and the actual amounts received for product sales in the month that settlement proceeds are received from the operator.
The following table disaggregates the Partnership’s revenue streams that are summarized as “Oil, natural gas and natural gas liquids revenues” on the consolidated statements of operations for the three and six months ended June 30, 2018.
Three Months Ended | Six Months Ended | |||||||
Oil revenues | $ | 7,018,563 | $ | 10,207,973 | ||||
Natural gas revenues | 292,454 | 375,607 | ||||||
Natural gas liquids revenues | 220,079 | 444,595 | ||||||
| $ | 7,531,096 | $ | 11,028,175 | |||||
Recently Adopted Accounting Standards
In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting model to enable entities to better portray their risk management activities in their financial statements and enhance the transparency and understandability of hedging activity. The standard simplifies the application of hedge accounting and reduces the administrative burden of hedge documentation requirements and assessing hedge effectiveness. The standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The standard requires a modified retrospective approach for all hedge relationships that exist on the date of adoption. The presentation and disclosure guidance is required only prospectively. The Partnership adopted this standard on January 1, 2018. As of January 1, 2018 and June 30, 2018, the Partnership did not have any outstanding hedge positions; therefore, the adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements.
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606), that amends the former revenue recognition guidance and provides a revised comprehensive revenue recognition model with customers that contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Throughout 2016 and 2017, the FASB issued several updates, including ASUs 2016-08, 2016-10, 2016-12, 2016-20, 2017-13 and 2017-14, respectively, to clarify specific topics originally described in ASU 2014-09. In August 2015, the FASB issued ASU No. 2015-14, which deferred the effective date of ASU 2014-09 to annual and interim periods beginning after December 15, 2017, and permitted early application for annual reporting periods beginning after December 15, 2016. The Partnership adopted this standard on January 1, 2018. The Partnership did not recognize any revenue for any period prior to adoption of this standard.
Recently Issued Accounting Standards
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets as right-of-use assets and lease liabilities. The standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The Partnership expects to adopt this standard as of January 1, 2019. Although the Partnership has not yet identified any material impact, the Partnership is still evaluating the impact this standard will have on its consolidated financial statements and related disclosures.
Note 3. Oil and Gas Investments
On February 1, 2018, the Partnership completed its purchase of the Bakken Assets for $87.5 million. In addition to using proceeds from its best-efforts offering, the Partnership partially funded the acquisition using proceeds from an unsecured term loan of $25.0 million (discussed below in Note 5. Debt) and an advance from a member of the General Partner of $7.0 million. The advance from a member of the General Partner was repaid in full in May 2018. At closing, the Bakken Assets were comprised of 204 producing wells and 30 wells in various stages of the drilling and completion process.
The Partnership accounted for this acquisition as a purchase of a group of similar assets, and therefore capitalized transaction costs associated with this acquisition. These acquisition-related costs included, but were not limited to, fees for advisory and consulting (discussed below), due diligence, legal, accounting, engineering and environmental review services. The Partnership has capitalized approximately $5.0 million in transaction costs in conjunction with the acquisition. The
Partnership also recorded an asset retirement obligation liability of approximately $0.1 million in conjunction with this acquisition. See Note 4. Asset Retirement Obligation below.
The Partnership adjusted the purchase price to reflect the operating revenues and expenses of the Bakken Assets between the acquisition effective date of September 1, 2017 and the closing date of February 1, 2018, in accordance with the closing conditions set forth in the purchase agreement. The net impact of the purchase price adjustments was a decrease to the purchase price of the asset of approximately $2.3 million.
The Partnership engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting the Partnership through closing and post-closing of the purchase agreement of the Bakken Assets. In the first quarter of 2018, the Partnership paid REI a total of approximately $5.3 million for its advisory and consulting services. REI is also entitled to a fee of 5% of the gross sales price in the event the Partnership disposes any or all of the Bakken Assets, if surplus funds are available after Payout to the holders of the Partnership’s common units, as defined in Note 6 below. Of the $5.3 million paid to REI, approximately $4.7 million of these services related to the acquisition of the Bakken Assets have been capitalized as part of the acquisition costs described above. REI is owned by entities that are controlled by Anthony F. Keating, III, Co-Chief Operating Officer of Energy 11 GP, LLC, and Michael J. Mallick, Co-Chief Operating Officer of Energy 11 GP, LLC. Glade M. Knight and David S. McKenney are the Chief Executive Officer and Chief Financial Officer, respectively, of Energy 11 GP, LLC as well as the Chief Executive Officer and Chief Financial Officer, respectively, of the General Partner. See Note 7. Related Parties below for additional information.
In total, the Partnership incurred approximately $2.9 million in capital drilling and completion costs for the period from February 1, 2018 to June 30, 2018. From February 1, 2018 to June 30, 2018, the Partnership participated in the drilling of 55 wells, of which 36 have been completed and 19 wells are in various stages of completion at June 30, 2018. To date, the Partnership has incurred approximately $2.9 million in capital expenditures and anticipates approximately $0.7 million remain to complete the 19 wells in various stages of completion.
The following unaudited pro forma financial information for the three and six months ended June 30, 2018 and 2017 have been prepared as if the acquisition of the Bakken Assets had occurred on January 1, 2017. The unaudited pro forma financial information was derived from the historical statements of operations of the Partnership and the historical financial statements of the sellers of the Bakken Assets. The unaudited pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisition of the Bakken Assets and related financings occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations.
Three Months Ended | Three Months Ended | Six Months Ended | Six Months Ended | |||||||||||||
Revenues | $ | 7,531,096 | $ | 3,423,571 | $ | 12,729,593 | $ | 6,262,434 | ||||||||
Net income | $ | 3,475,952 | $ | 1,057,017 | $ | 5,664,109 | $ | 1,938,596 | ||||||||
On June 29, 2018, the Partnership, through a wholly-owned subsidiary (the “Buyer”), entered into a Purchase and Sale Agreement (“Purchase Agreement No. 2”) with Bruin E&P Non-Op Holdings, LLC (“Seller”), for the potential purchase of an additional portion of the Seller’s interest in the Bakken Assets, resulting in the Partnership acquiring an additional approximate average 2.7% non-operated working interest (the “Target Assets”). If all conditions to closing on the Target Assets are met under the Purchase Agreement No. 2, the Partnership’s non-operated working interest in the Bakken Assets would increase to approximately a total of 5.4%.
Pursuant to Purchase Agreement No. 2, the purchase price for the Target Assets is $82.5 million, subject to customary adjustments. On June 29, 2018, the Partnership funded a deposit of 5% of the purchase price, or $4,125,000 (the “Deposit”), to the Seller to be applied toward the purchase price at closing or to be released to the Seller if the transaction does not close by the outside closing date due to the Buyer’s breach of Purchase Agreement No. 2. In the event the transaction does not close due to a breach by Sellers, the Deposit will be refunded to the Partnership. If the Buyer does not perform under the contract as a result of its diligence review or otherwise breach Purchase Agreement No. 2, the Sellers’ sole remedy against the Buyer is release of the Deposit to the Seller. The final settlement purchase price is subject to customary post-closing adjustments, as defined and identified in Purchase Agreement No. 2.
The closing of Purchase Agreement No. 2 is subject to the satisfaction of a number of required conditions which currently remain unsatisfied under Purchase Agreement No. 2. Consummation of the acquisition is subject to the Buyer’s satisfactory completion of the review of title, environmental investigations, financial analysis and geological analysis, obtaining sufficient financing to fund the purchase price and other due diligence. Accordingly, there can be no assurance at this time that all of the conditions precedent to consummating Purchase Agreement No. 2 will be satisfied, that the Partnership will find the results of its diligence investigation acceptable, that the Partnership will be able to obtain sufficient financing on terms reasonably acceptable or that the transaction will be successfully completed.
The Partnership has engaged REI to perform advisory and consulting services and support the Partnership through closing of Purchase Agreement No. 2, including assistance with due diligence related to the Target Assets and obtaining financing for the proposed transaction. The Partnership will pay REI a total of approximately $4.1 million for its advisory and consulting services; the $4.1 million has been accrued in Due to related parties on the consolidated balance sheets as of June 30, 2018. REI is also entitled to a fee of 5% of the gross sales price in the event the Partnership disposes any or all of the Target Assets, if surplus funds are available after Payout to the holders of the Partnership’s common units, as defined below in Note 6.
Note 4. Asset Retirement Obligations
The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows:
2018 | ||||
Balance as of January 1, 2018 | $ | - | ||
Liabilities incurred on February 1, 2018 (acquisition) | 133,155 | |||
Well additions | 5,562 | |||
Accretion | 3,051 | |||
Balance as of June 30, 2018 | $ | 141,768 | ||
Note 5. Debt
On January 16, 2018, the Partnership entered into a loan agreement with Bank of America, N.A., as the lender, for an unsecured term loan (“Term Loan”) of $25.0 million. The Partnership used the $25.0 million proceeds from the Term Loan to partially fund the initial purchase of the Bakken Assets, as described in Note 3. Oil and Gas Investments above. The Term Loan bears interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. Interest is payable monthly. The maturity date is January 15, 2019.
The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Under the terms of the loan agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. Glade M. Knight, the General Partner’s Chief Executive Officer, and David S. McKenney, the General Partner’s Chief Financial Officer, have guaranteed repayment of the Term Loan and have not and will not receive any consideration in exchange for providing this guarantee.
As of June 30, 2018, the outstanding balance on the Term Loan was $15.0 million. The outstanding balance at June 30, 2018 approximates its fair market value. The Partnership estimated the fair value of its Term Loan by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.
Note 6. Capital Contribution and Partners’ Equity
At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below), and has been and will be reimbursed for its documented third party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.
As of July 25, 2017, the Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit. In October 2017, the Partnership completed the sale of all common units at $19.00 (2,631,579 common units). In accordance with the prospectus, all subsequent common units are being sold at $20.00 per common unit. As of June 30, 2018, the Partnership had completed the sale of 5.2 million common units for gross proceeds of approximately $100.5 million and proceeds net of offering costs of approximately $93.9 million.
The Partnership intends to continue to raise capital through its best-efforts offering of common units by the Managing Dealer at $20.00. Under the agreement with the Managing Dealer, the Managing Dealer receives a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through June 30, 2018, the Dealer Manager Incentive Fees are approximately $4.0 million, subject to Payout (defined below).
Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.
The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.
All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:
● | First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. |
● | Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. |
All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.
For the three and six months ended June 30, 2018, the Partnership paid distributions of $0.349041 and $0.698082 per common unit, or $1.4 million and $2.6 million, respectively.
Note 7. Related Parties
The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related
party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions.
The Partnership will reimburse the General Partner for any costs incurred by the General Partner for certain expenses, which include costs for organizing the Partnership and costs incurred in the offering of the common units. The Partnership has also agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. In accordance with the limited partner agreement, subsequent to the Partnership’s first asset purchase which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. Based upon the total gross equity proceeds as of June 30, 2018, the management fee for the three and six months ended June 30, 2018 due to the General Partner is approximately $126,000 and $185,000, respectively. As of June 30, 2018, the accrued management fee due to the General Partner is approximately $185,000, which has been accrued on the consolidated balance sheets in Due to related parties at June 30, 2018 and included in General and administrative expenses on the consolidated statements of operations.
The Partnership also will reimburse the General Partner for certain general and administrative costs. For the three and six months ended June 30, 2018, approximately $102,000 and $183,000 of general and administrative costs were incurred by a member of the General Partner and will be reimbursed by the Partnership. At June 30, 2018, the approximately $102,000 that was due to a member of the General Partner is included in Due to related parties in the consolidated balance sheets.
In January 2018, the Partnership received an advance of $7.0 million from a member of the General Partner to partially fund the purchase of the Bakken Assets. The Partnership repaid a member of the General Partner in full in May 2018. The advance did not bear interest and the member of the General Partner did not receive any compensation for the advance.
The Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 that will give the Partnership access to Energy 11’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The shared day-to-day costs will be split evenly between the two partnerships and any direct third-party costs will be paid by the party receiving the services. The shared costs will be based on actual costs incurred with no mark-up or profit to the Partnership. The agreement may be terminated at any time by either party upon 60 days written notice.
As noted above, the cost sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner. In addition to certain accounting and asset management resources, the Partnership and Energy 11 share the rent expense for leased office space (leased from an affiliate of a member of the general partner of Energy 11) in Oklahoma City, Oklahoma along with the compensation due to the President of Energy 11’s general partner. For the three and six months ended June 30, 2018, approximately $64,000 and $111,000, respectively, of expenses subject to the cost sharing agreement were incurred by the Partnership and will be reimbursed to Energy 11. At June 30, 2018, approximately $64,000 is due from the Partnership to Energy 11 and is included in Due to related parties in the consolidated balance sheets.
Note 8. Subsequent Events
In July 2018, the Partnership closed on the issuance of approximately 0.4 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $8.4 million and proceeds net of selling and marketing costs of approximately $7.9 million.
In July 2018, the Partnership declared and paid $0.6 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.
Report of Independent Registered Public Accounting Firm
To the Shareholders and the General Partner of Energy Resources 12, L.P.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Energy Resources 12, L.P. (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, Partners’ equity, and cash flows for the year ended December 31, 2017 and the period December 30, 2016 (initial capitalization) through December 31, 2016, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2017 and 2016, and the results of operations and its cash flows for the year ended December 31, 2017 and for the period December 30, 2016 (initial capitalization) through December 31, 2016, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2017.
Richmond, Virginia
February 26, 2018
Energy Resources 12, L.P.
Consolidated Balance Sheets
December 31, 2017 | December 31, 2016 | |||||||
Assets | ||||||||
Cash | $ | 46,859,728 | $ | 1,000 | ||||
Deposit for potential acquisition | 8,750,000 | - | ||||||
Deferred acquisition costs | 4,884,208 | - | ||||||
Deferred offering costs | - | 22,975 | ||||||
Total Assets | $ | 60,493,936 | $ | 23,975 | ||||
Liabilities | ||||||||
Accounts payable and accrued expenses | $ | 5,448,409 | $ | 23,245 | ||||
Total Liabilities | 5,448,409 | 23,245 | ||||||
Partners’ Equity | ||||||||
Limited partners’ interest (3,191,231 and 0 common units issued and outstanding, respectively) | 55,045,742 | 723 | ||||||
General partner’s interest | (215 | ) | 7 | |||||
Total Partners’ Equity | 55,045,527 | 730 | ||||||
Total Liabilities and Partners’ Equity | $ | 60,493,936 | $ | 23,975 | ||||
See notes to consolidated financial statements.
Energy Resources 12, L.P.
Consolidated Statements of Operations
Year Ended | For the period December 30, 2016 (Initial Capitalization) through December 31, 2016 | |||||||
Revenue | $ | - | $ | - | ||||
Transaction costs | 525,000 | - | ||||||
General and administrative expenses | 99,410 | 270 | ||||||
Operating loss | (624,410 | ) | (270 | ) | ||||
Interest income, net | 114,163 | - | ||||||
Net loss | $ | (510,247 | ) | $ | (270 | ) | ||
Basic and diluted net income (loss) per common unit | $ | (0.48 | ) | $ | - | |||
Weighted average common units outstanding - basic and diluted | 1,067,941 | - | ||||||
See notes to consolidated financial statements.
Energy Resources 12, L.P.
Consolidated Statements of Partners’ Equity
Limited Partner | General Partner | Total Partners’ Equity | ||||||||||
Initial capitalization - December 30, 2016 | $ | 990 | $ | 10 | $ | 1,000 | ||||||
2016 Net loss | (267 | ) | (3 | ) | (270 | ) | ||||||
Balance - December 31, 2016 | 723 | 7 | 730 | |||||||||
Net proceeds from issuance of common units | 57,014,432 | - | 57,014,432 | |||||||||
Distributions to organizational limited partner | (990 | ) | - | (990 | ) | |||||||
Distributions declared and paid to common units ($0.598357 per unit) | (1,458,398 | ) | - | (1,458,398 | ) | |||||||
2017 Net loss | (510,025 | ) | (222 | ) | (510,247 | ) | ||||||
Balance - December 31, 2017 | $ | 55,045,742 | $ | (215 | ) | $ | 55,045,527 | |||||
See notes to consolidated financial statements.
Energy Resources 12, L.P.
Consolidated Statements of Cash Flows
For the year ended | For the period December 30, 2016 (Initial Capitalization) through December 31, 2016 | |||||||
Cash flow from operating activities: | ||||||||
Net loss | $ | (510,247 | ) | $ | (270 | ) | ||
Changes in operating assets and liabilities: | ||||||||
Deferred acquisition costs | (4,190 | ) | - | |||||
Accounts payable and accrued expenses | 560,832 | 270 | ||||||
Net cash used in operating activities | 46,395 | - | ||||||
Cash flow from investing activities | ||||||||
Deposit for acquisition of oil, natural gas and natural gas liquids properties | (8,750,000 | ) | - | |||||
Net cash used in investing activities | (8,750,000 | ) | - | |||||
Cash flow from financing activities | ||||||||
Net proceeds related to issuance of common units | 57,020,731 | - | ||||||
Net proceeds from line of credit | 229,000 | - | ||||||
Payments on line of credit | (229,000 | ) | - | |||||
Distributions paid to limited partners | (1,458,398 | ) | - | |||||
Net cash provided by financing activities | 55,562,333 | - | ||||||
Increase in cash and cash equivalents | 46,858,728 | - | ||||||
Cash and cash equivalents, beginning of period | 1,000 | 1,000 | ||||||
Cash and cash equivalents, end of period | $ | 46,859,728 | $ | 1,000 | ||||
Interest paid | $ | 1,420 | $ | - | ||||
Supplemental information: | ||||||||
Accrued deferred costs for potential acquisition | 4,880,018 | - | ||||||
Accrued deferred offering costs | - | 22,975 | ||||||
See notes to consolidated financial statements.
Energy Resources 12, L.P.
Notes to Consolidated Financial Statements
December 31, 2017
Note 1. Partnership Organization
Energy Resources 12, L.P. (together with its wholly-owned subsidiary, the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership is offering common units of limited partner interest (the “common units”) on a best-efforts basis with the intention of raising up to $350,000,001 of capital, consisting of 17,631,579 common units. The Partnership’s offering was declared effective by the Securities and Exchange Commission (“SEC”) on May 17, 2017. As of July 25, 2017, the Partnership completed the sale of the minimum offering of 1,315,790 common units. The subscribers to the common units were admitted as Limited Partners of the Partnership at the initial closing of the offering and the Partnership has been admitting additional Limited Partners monthly since that time.
The Partnership’s primary investment objectives are to (i) acquire producing and non-producing oil and gas properties with development potential to be operated by third-party operators, and to enhance the value of the properties through drilling and other development activities, (ii) make distributions to the holders of the common units, (iii) engage in a liquidity transaction after five to seven years, in which all properties are sold and the sales proceeds are distributed to the partners, merge with another entity, or list the common units on a national securities exchange, and (iv) permit holders of common units to invest in oil and gas properties in a tax efficient basis. The proceeds from the sale of the common units primarily will be used to acquire producing and non-producing oil and natural gas properties onshore in the United States, and to develop those properties.
The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. David Lerner Associates, Inc. (the “Managing Dealer”), is acting as the dealer manager for the offering of the common units.
The Partnership’s fiscal year ends on December 31.
Note 2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”).
Cash and Cash Equivalents
Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.
Offering Costs
The Partnership is raising capital through an on-going best-efforts offering of units by the Managing Dealer, which receives a selling commission and a marketing expense allowance based on proceeds of the units sold. Additionally, the Partnership has incurred other offering costs including legal, accounting and reporting services. These offering costs are recorded by the Partnership as a reduction of partners’ equity. As of December 31, 2017, the Partnership had sold 3.2 million common units for gross proceeds of $61.2 million and proceeds net of offering costs of $57.0 million.
Use of Estimates
The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Income Tax
The Partnership is taxed as a partnership for federal and state income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.
The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.
Property and Depreciation, Depletion and Amortization
The Partnership will account for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.
No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
Impairment
The Partnership will assess its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.
Accounting for Asset Retirement Obligations
The Partnership will have significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
The Partnership will record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.
Revenue Recognition
Oil, natural gas and natural gas liquids revenues will be recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.
The Partnership will not operate its oil and natural gas properties and, therefore, will receive actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well will be used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership will adjust the estimated accruals of revenue to actual production in the period actual production is determined.
Net Loss per Common Unit
Basic net loss per common unit is computed as net loss divided by the weighted average number of common units outstanding during the period. Diluted net loss per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the year ended December 31, 2017. As a result, basic and diluted outstanding common units were the same. There were no outstanding common units for the period ended December 31, 2016. The Incentive Distribution Rights (as discussed in Note 3) are not included in net loss per common unit until such time that it is probable Payout (as discussed in Note 3) would occur.
Recently Adopted Accounting Standards
In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2017-01, Business Combinations (Topic 805), which amends the existing accounting standards to clarify the definition of a business and assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities, the guidance is effective for reporting periods beginning after December 15, 2017,
including interim periods within those periods, and should be applied prospectively on or after the effective date. The Partnership adopted this standard effective January 1, 2017.
Recently Issued Accounting Standards
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), that amends the former revenue recognition guidance and provides a revised comprehensive revenue recognition model with customers that contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Throughout 2016, the FASB issued several updates, including ASUs 2016-08, 2016-10, 2016-12, 2016-20, 2017-13 and 2017-14, respectively, to clarify specific topics originally described in ASU 2014-09. In August 2015, the FASB issued ASU No. 2015-14, which deferred the effective date of ASU 2014-09 to annual and interim periods beginning after December 15, 2017, and permitted early application for annual reporting periods beginning after December 15, 2016. The Partnership adopted this standard on January 1, 2018. The Partnership did not recognize any revenue for any period prior to adoption of this standard.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets as right-of-use assets and lease liabilities. The standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The Partnership expects to adopt this standard as of January 1, 2019. The Partnership is still evaluating the impact this standard will have on its consolidated financial statements and related disclosures.
In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting model to enable entities to better portray their risk management activities in their financial statements and enhance the transparency and understandability of hedging activity. The standard simplifies the application of hedge accounting and reduces the administrative burden of hedge documentation requirements and assessing hedge effectiveness. The standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The standard requires a modified retrospective approach for all hedge relationships that exist on the date of adoption. The presentation and disclosure guidance is required only prospectively. The Partnership plans to adopt this standard in the first quarter of 2018. As of December 31, 2017, the Partnership has no outstanding hedge positions; therefore, the adoption of this standard is not expected to have a material impact on the Partnership’s consolidated financial statements.
Note 3. Oil and Gas Investments
On November 21, 2017, Energy Resources 12 Operating Company, LLC (“Buyer”), a wholly-owned subsidiary of the Partnership, entered into a Purchase and Sale Agreement (“Purchase Agreement”) with Bruin E&P Non-Op Holdings, LLC (“Seller”), for the potential purchase of Seller’s interest in certain non-operated oil and gas properties and the related rights, resulting in an approximate average 3.1% non-operated working interest in approximately 204 existing producing wells and approximately 547 future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Buyer closed on the purchase of the Bakken Assets on February 1, 2018. The Buyer will not be the operator of the Bakken Assets; the current, experienced operators will continue to operate the Bakken Assets on behalf of the Buyer and other working interest owners.
Pursuant to the Purchase Agreement, the purchase price for the Bakken Assets is $87.5 million. On November 21, 2017, the Partnership, on behalf of the Buyer, funded a deposit of 10% of the purchase price, or $8.75 million, to the Seller that was applied toward the purchase price at closing. The final settlement purchase price is subject to the customary post-closing adjustments, as defined and identified in the Purchase Agreement.
The closing of the Purchase Agreement was subject to the satisfaction of a number of required conditions which, at December 31, 2017, remained unsatisfied under the Purchase Agreement. Consummation of the acquisition was subject to the Buyer’s satisfactory completion of the review of title, environmental investigations, financial analysis and geological analysis, obtaining sufficient financing to fund the purchase price and other due diligence.
The Partnership has engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting the Buyer through closing and post-closing of the Purchase Agreement. The Partnership will pay REI a total of approximately $5.3 million for its advisory and consulting services. REI is also entitled to a fee of 5% of the gross
sales price in the event the Buyer disposes any or all of the Bakken Assets, if surplus funds are available after Payout to the holders of the Partnership’s common units, as defined Note 4 below. REI is owned by entities that are controlled by Anthony F. Keating, III, Co-Chief Operating Officer of Energy 11 GP, LLC, and Michael J. Mallick, Co-Chief Operating Officer of Energy 11 GP, LLC. Glade M. Knight and David S. McKenney are the Chief Executive Officer and Chief Financial Officer, respectively, of Energy 11 GP, LLC as well as the Chief Executive Officer and Chief Financial Officer, respectively, of the General Partner. See Note 6. Related Parties below for additional information.
The acquisition-related costs incurred for legal, accounting and environmental review services through December 31, 2017 of approximately $4.9 million were included in Deferred costs for potential acquisition on the Partnership’s consolidated balance sheets. Approximately $0.5 million of the fee payable to REI related to due diligence work on potential acquisitions that were not pursued, and therefore, were recorded as Transaction costs in the Partnership’s consolidated statements of operations.
Note 4. Capital Contribution and Partners’ Equity
At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below), and has been and will be reimbursed for its documented third party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.
As of July 25, 2017, the Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit. As of December 31, 2017, the Partnership had completed the sale of 3,191,231 common units for gross proceeds of approximately $61.2 million and proceeds net of offering costs of approximately $57.0 million. In October 2017, the Partnership completed the sale of all common units at $19.00 (2,631,579 common units). In accordance with the prospectus, all subsequent common units are being sold at $20.00 per common unit.
The Partnership intends to continue to raise capital through its best-efforts offering of common units by the Managing Dealer at $20.00. Under the agreement with the Managing Dealer, the Managing Dealer receives a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through December 31, 2017, the Dealer Manager Incentive Fees are approximately $2.4 million, subject to Payout (defined below).
Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.
The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.
All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:
● | First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. |
● | Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. |
All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.
For the year ended December 31, 2017, the Partnership paid distributions of $0.598357 per common unit, or $1.5 million.
Note 5. Line of Credit
In February 2017, the Partnership obtained an unsecured line of credit with Bank of America in the principal amount of $500,000 to fund some of its offering and operating costs. On July 25, 2017, the Partnership repaid the outstanding balance on the line of credit of $229,000, which bore interest at a variable rate based on the London InterBank Offered Rate (LIBOR), using proceeds from the sale of common units without a prepayment premium or penalty.
Glade M. Knight, the General Partner’s Chief Executive Officer, and David S. McKenney, the General Partner’s Chief Financial Officer, had guaranteed repayment of the line of credit and did not receive any consideration in exchange for providing this guarantee.
Note 6. Related Parties
The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions.
The Partnership has agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. Subsequent to the Partnership’s first asset purchase, the Partnership will pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its offering as outlined in the prospectus. The fees paid to the General Partner will be expensed as incurred. In addition, the Partnership will also reimburse the General Partner for any costs incurred by the General Partner in organizing the Partnership or incurred in the offering of the common units. For the year ended December 31, 2017, approximately $57,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At December 31, 2017, approximately $34,000 was due to a member of the General Partner. See discussion above in Note 3. Oil and Gas Investments regarding costs incurred and payable to a related party for due diligence and advisory services provided on the acquisition of the Bakken Assets.
The Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”). The Partnership has and anticipates that it will share accounting and administrative resources, including personnel, with Energy 11 to ensure effective staffing of the Partnership. The cost of these accounting and administrative resources will be shared between the partnerships. See discussion below in Note 7. Subsequent Events on the cost sharing agreement.
Note 7. Subsequent Events
In January 2018, the Partnership closed on the issuance of approximately 0.2 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $4.2 million and proceeds net of selling and marketing costs of approximately $4.0 million.
In January 2018, the Partnership declared and paid $0.3 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.
On January 16, 2018, the Partnership entered into a loan agreement with Bank of America, N.A., as the lender, for an unsecured term loan of $25 million. The Term Loan bears interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. The maturity date is January 15, 2019.
On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 to provide access to Energy 11’s personnel and administrative resources. The personnel will provide accounting, asset management and other day-to-day management support for the Partnership. The shared day-to-day costs will be split evenly between the two partnerships and any direct third-party costs will be paid by the party receiving the services. The shared costs will be based on actual costs incurred with no mark-up or profit for Energy 11. The agreement may be terminated at any time by either party upon 60 days written notice. The officers and members of the Partnership’s General Partner are also officers and members of the general partner of Energy 11.
On February 1, 2018, the Partnership, through its wholly-owned subsidiary, closed on the acquisition of Seller’s interest in the Bakken Assets discussed in Note 3. Oil and Gas Investments above. The purchase price of $87.5 million, subject to customary adjustments, was funded by net proceeds from the Partnership’s ongoing public offering, proceeds from the unsecured term loan discussed above and an advance from a member of the General Partner of $7.0 million. The advance does not bear interest and the member of the General Partner did not receive any compensation for the advance. The unsecured term loan and the advance are planned to be repaid with future proceeds from the Partnership’s ongoing public offering.
In February 2018, the Partnership closed on the issuance of approximately 0.2 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $4.0 million and proceeds net of selling and marketing costs of approximately $3.7 million.
In February 2018, the Partnership declared and paid $0.4 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.
REPORT OF INDEPENDENT AUDITORS
The Managing General Partner of Energy Resources 12, L.P.
We have audited the accompanying combined statements of revenues and direct operating expenses (the “financial statements”) of the assets under contract to be acquired by a subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC for the period from January 1, 2017 through September 30, 2017, and for the year ended December 31, 2016, and the related notes to the financial statements.
Management’s Responsibility for the Financial Statements
Energy Resources 12, L.P and Bruin E&P Non-Op Holdings, LLC management are responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the assets under contract to be acquired by a subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC for the period from January 1, 2017 through September 30, 2017, and for the year ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
Basis of Presentation
The accompanying financial statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1. The presentation is not intended to be a complete financial statement presentation of the assets under contract to be acquired as described above.
/s/ Ernst & Young LLP
Richmond, Virginia
February 1, 2018
COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF PROPERTIES UNDER CONTRACT FOR PURCHASE BY A SUBSIDIARY OF ENERGY RESOURCES 12, L.P. FROM BRUIN E&P NON-OP HOLDINGS, LLC UNDER AGREEMENT DATED NOVEMBER 21, 2017
Nine months ended September 30, 2017 | Year ended December 31, 2016 | |||||||
Revenues - oil, natural gas and natural gas liquids sales | $ | 10,615,149 | $ | 9,059,135 | ||||
Direct operating expenses | 3,201,668 | 3,513,057 | ||||||
Revenues in excess of direct operating expenses | $ | 7,413,481 | $ | 5,546,078 | ||||
See Notes to Combined Statements of Revenues and Direct Operating Expenses
NOTES TO COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF PROPERTIES UNDER CONTRACT FOR PURCHASE BY A SUBSIDIARY OF ENERGY RESOURCES 12, L.P. FROM BRUIN E&P NON-OP HOLDINGS, LLC UNDER AGREEMENT DATED NOVEMBER 21, 2017
Nine months ended September 30, 2017 and
Year ended December 31, 2016
Note 1. Basis of Presentation
Bruin E&P Non-Op Holdings, LLC (the “Company”) is a limited liability company created on December 1, 2016, for the purpose of acquiring producing and non-producing oil and natural gas properties with development potential within the Bakken Shale in northwest North Dakota. The Company is a wholly-owned subsidiary of Bruin E&P Partners, LLC, a limited liability company primarily engaged in the exploration, acquisition, development and production of onshore oil and natural gas properties in the United States. On December 9, 2016, the Company entered into an agreement with Enerplus Corporation, through its subsidiary Enerplus Resources (USA) Corporation, (collectively, “Enerplus”) to acquire non-operated oil and natural gas properties (the “Assets”) in North Dakota for $292 million in cash, subject to customary purchase price adjustments. The transaction closed on December 30, 2016.
On November 21, 2017, the Company entered into an agreement with Energy Resources 12, L.P. through its wholly-owned subsidiary, Energy Resources 12 Operating Company, LLC (the “Buyer”), for the potential sale of the Company’s interest in non-operated oil and gas properties and the related rights of a portion of the Assets for $87.5 million, subject to customary purchase price adjustments. The sale would result in the divestiture by the Company of an approximate average 3.1% non-operated working interest in approximately 204 existing producing wells and approximately 547 future development locations, predominantly in the counties of McKenzie, Dunn, McLean and Mountrail, North Dakota. The transaction closed on February 1, 2018. The accompanying combined statements of revenues and direct operating expenses reflect the portion of the Assets applicable to the interests under contract by the Buyer (the “Properties”).
Revenues in the accompanying combined statements of revenues and direct operating expenses are recognized on the sales method. Direct operating expenses are recognized on the accrual method and consist of monthly operator overhead and other direct costs of operating the Properties. Included in direct operating costs are costs associated with field operating expenses, workovers and monthly operator overhead.
The accompanying audited statements of revenues and direct operating expenses were derived from the Company’s historical accounting records for the period of ownership and from Enerplus’s historical accounting records prior to the purchase of the Assets by the Company. The combined statements of revenues and direct operating expenses represent the revenues and direct operating expenses for the Properties for the period of Enerplus ownership (January 1, 2016 to December 29, 2016) and for the period of the Company’s ownership (December 30, 2016 to September 30, 2017).
The combined statements of revenues and direct operating expenses vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Properties including, but not limited to, general and administrative expenses and interest expense. These costs were not separately allocated to the Properties in the accounting records of the Company. In addition, these allocations, if made using historical general and administrative and debt structures, would not produce allocations that would be indicative of the historical performance of the Properties had it been a Buyer property due to the differing size, structure, operations and accounting policies of the Company and Buyer. The accompanying financial statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs that Buyer will incur upon the allocation of the purchase price paid for the Properties. The accompanying statements also do not include provisions for federal or state income taxes.
Furthermore, no balance sheet has been presented for the Properties because the acquired properties were not accounted for as a separate subsidiary or division of the Company and complete financial statements are not available, nor has information about the Properties’ operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical statements of revenues and direct operating expenses of the Properties are presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission (‘‘SEC’’) Regulation S-X.
These statements of revenues and direct operating expenses are not indicative of the results of operations for the Properties on a go forward basis.
Note 2. Summary of Significant Accounting Policies
Use of Estimates
The combined statements of revenues and direct operating expenses are derived from the historical operating statements of the Company and Enerplus. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the respective reporting periods. Actual results could be different from those estimates.
Revenue Recognition
Total revenues in the accompanying financial statements include the sale of crude oil, natural gas and natural gas liquids (“NGL”), net of royalties. The Company recognizes revenues when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. Oil and gas revenues included in these statements are recorded on the sales method, under which revenues are based on the oil, natural gas liquids and natural gas delivered rather than the net revenue interest share of oil and gas produced. There were no significant imbalances with other revenue interest owners during the nine months ended September 30, 2017 and the year ended December 31, 2016.
Direct Operating Expenses
Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Properties. The direct operating expenses include lease operating, production and ad valorem taxes, exploration costs, and processing and transportation expenses. Lease operating expenses include lifting costs, well repair expenses, facility maintenance expenses, well workover costs and other field-related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment and facilities directly related to oil and gas production activities.
Note 3. Contingencies
The activities of the Properties may become subject to potential claims and litigation in the normal course of operations. The Company is not aware of any liability related to any pending or threatened litigation that could have a material adverse effect on the operations or financial results of the Properties.
Note 4. Subsequent Events
Management has evaluated subsequent events through February 1, 2018, the date the accompanying combined statements of revenue and direct operating expenses were available to be issued, and is not aware of any events that have occurred that require adjustments to or disclosure in these financial statements.
Note 5. Supplemental Oil and Natural Gas Reserve Information (Unaudited)
The following unaudited information regarding the Properties’ oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements required by the Securities and Exchange Commission and the Financial Accounting Standards Board. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. “Revisions of previous estimates” in the table below represent changes in previous reserve estimates, either upward or downward, resulting from a change in economic factors, such as commodity prices, operating costs or development costs, or resulting from information obtained from the Partnership’s production history.
Reserve Quantity Information
Below are the net quantities of net proved developed and undeveloped reserves and proved developed reserves of the Properties:
For the nine months ended September 30, 2017 | For the year ended December 31, 2016 | |||||||||||||||||||||||||||||||
Oil (Bbls) | Gas (Mcf) | NGL (Bbls) | Total (BOE) | Oil (Bbls) | Gas (Mcf) | NGL (Bbls) | Total (BOE) | |||||||||||||||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||||||||||||||||||
Beginning of period | 13,845,805 | 8,204,345 | 1,237,940 | 16,451,136 | 806,609 | 815,742 | 108,728 | 1,051,294 | ||||||||||||||||||||||||
Purchase of mineral in place | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Extensions, discoveries and other additions | 45,350 | 24,940 | 3,810 | 53,317 | 12,375,495 | 6,887,935 | 1,050,055 | 14,573,539 | ||||||||||||||||||||||||
Revisions of previous estimates | 268,754 | 184,815 | 41,681 | 341,237 | 894,797 | 689,176 | 106,136 | 1,115,796 | ||||||||||||||||||||||||
Production | (224,605 | ) | (135,681 | ) | (18,738 | ) | (265,957 | ) | (231,096 | ) | (188,508 | ) | (26,979 | ) | (289,493 | ) | ||||||||||||||||
End of period | 13,935,304 | 8,278,419 | 1,264,693 | 16,579,733 | 13,845,805 | 8,204,345 | 1,237,940 | 16,451,136 | ||||||||||||||||||||||||
Proved developed reserves: | ||||||||||||||||||||||||||||||||
Beginning of period | 1,657,780 | 1,430,790 | 203,435 | 2,099,680 | 806,609 | 815,742 | 108,728 | 1,051,294 | ||||||||||||||||||||||||
Purchase of mineral in place | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Extensions, discoveries and other additions | 610,200 | 334,770 | 51,130 | 717,125 | 187,470 | 114,380 | 15,550 | 222,083 | ||||||||||||||||||||||||
Revisions of previous estimates | 122,944 | 63,395 | 23,131 | 156,641 | 894,797 | 689,176 | 106,136 | 1,115,796 | ||||||||||||||||||||||||
Production | (224,605 | ) | (135,681 | ) | (18,738 | ) | (265,957 | ) | (231,096 | ) | (188,508 | ) | (26,979 | ) | (289,493 | ) | ||||||||||||||||
End of period | 2,166,319 | 1,693,274 | 258,958 | 2,707,489 | 1,657,780 | 1,430,790 | 203,435 | 2,099,680 | ||||||||||||||||||||||||
In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Company uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period.
The oil and natural gas prices used in computing the Properties’ reserves as of September 30, 2017 were $49.81 per barrel of oil and $3.01 per Mcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Properties’ reserves as of September 30, 2017 were $42.31 per barrel of oil, $2.64 per Mcf of natural gas and $13.75 per barrel of NGL.
The oil and natural gas prices used in computing the Properties’ reserves as of January 1, 2017 were $42.75 per barrel of oil and $2.48 per Mcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Properties’ reserves as of January 1, 2017 were $35.25 per barrel of oil, $2.11 per Mcf of natural gas and $11.78 per barrel of NGL.
The oil, natural gas and NGL prices used in computing the Properties’ reserves as of January 1, 2016 were $50.28 per barrel of oil and $2.58 per Mcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Properties’ reserves as of January 1, 2016 were $42.78 per barrel of oil, ($0.42) per Mcf of natural gas and $6.42 per barrel of NGL.
Standardized Measure of Discounted Future Net Cash Flows
Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.
The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC, and as such, do not necessarily reflect expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.
September 30, 2017 | December 31, 2016 | |||||||
Future cash inflows | $ | 628,683,864 | $ | 519,960,730 | ||||
Future production costs | (203,735,639 | ) | (193,035,240 | ) | ||||
Future development costs | (72,128,760 | ) | (74,633,030 | ) | ||||
Future net cash flows | 352,819,465 | 252,292,460 | ||||||
10% annual discount | (213,695,253 | ) | (165,398,740 | ) | ||||
Standardized measure of discounted future net cash flows | $ | 139,124,212 | $ | 86,893,720 | ||||
Changes in the standardized measure of discounted future net cash flows are as follows:
For the nine months ended September 30, 2017 | For the year ended December 31, 2016 | |||||||
Standardized measure at beginning of period | $ | 86,893,720 | $ | 12,347,086 | ||||
Changes resulting from: | ||||||||
Acquisition of reserves | - | - | ||||||
Sales of oil, natural gas and NGLs, net of production costs | (7,413,481 | ) | (5,546,078 | ) | ||||
Net changes in prices and production costs | 44,246,340 | (2,728,485 | ) | |||||
Development costs incurred during the period | 9,008,532 | 1,505,546 | ||||||
Revisions of previous estimates | 3,884,831 | 155,948,681 | ||||||
Change in estimated future development costs | 2,504,270 | (74,633,030 | ) | |||||
Standardized measure of discounted future net cash flows | $ | 139,124,212 | $ | 86,893,720 | ||||
REPORT OF INDEPENDENT AUDITORS
The Managing General Partner of Energy Resources 12, L.P.
We have audited the accompanying combined statements of revenues and direct operating expenses (the “financial statements”) of the assets acquired by a subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC for the years ended December 31, 2017 and 2016, and the related notes to the financial statements.
Management’s Responsibility for the Financial Statements
Energy Resources 12, L.P and Bruin E&P Non-Op Holdings, LLC management are responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the assets acquired by a subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC for the years ended December 31, 2017 and 2016, in conformity with U.S. generally accepted accounting principles.
Basis of Presentation
The accompanying financial statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1. The presentation is not intended to be a complete financial statement presentation of the assets acquired as described above.
/s/ Ernst & Young LLP
Richmond, Virginia
September 5, 2018
COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF PROPERTIES ACQUIRED BY A SUBSIDIARY OF ENERGY RESOURCES 12, L.P. FROM BRUIN E&P NON-OP HOLDINGS, LLC UNDER AGREEMENT DATED JUNE 29, 2018
Six months ended June 30, 2018 | Year ended December 31, 2017 | Year ended December 31, 2016 | ||||||||||
(Unaudited) | ||||||||||||
Revenues - oil, natural gas and natural gas liquids sales | $ | 12,602,297 | $ | 14,668,131 | $ | 8,968,542 | ||||||
Direct operating expenses | 3,652,314 | 4,299,367 | 3,477,926 | |||||||||
Revenues in excess of direct operating expenses | $ | 8,949,983 | $ | 10,368,764 | $ | 5,490,616 | ||||||
See Notes to Combined Statements of Revenues and Direct Operating Expenses
NOTES TO COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF PROPERTIES ACQUIRED BY A SUBSIDIARY OF ENERGY RESOURCES 12, L.P. FROM BRUIN E&P NON-OP HOLDINGS, LLC UNDER AGREEMENT DATED JUNE 29, 2018
Six months ended June 30, 2018 (unaudited),
Years ended December 31, 2017 and 2016
Note 1. Basis of Presentation
Bruin E&P Non-Op Holdings, LLC (the “Company”) is a limited liability company created on December 1, 2016, for the purpose of acquiring producing and non-producing oil and natural gas properties with development potential within the Bakken Shale in northwest North Dakota. The Company is a wholly-owned subsidiary of Bruin E&P Partners, LLC, a limited liability company primarily engaged in the exploration, acquisition, development and production of onshore oil and natural gas properties in the United States. On December 9, 2016, the Company entered into an agreement with Enerplus Corporation, through its subsidiary Enerplus Resources (USA) Corporation, (collectively, “Enerplus”) to acquire non-operated oil and natural gas properties predominantly in the counties of McKenzie, Dunn, McLean and Mountrail, North Dakota (the “Bakken Assets”) for $292 million in cash, subject to customary purchase price adjustments. The transaction closed on December 30, 2016.
On November 21, 2017, the Company entered into an agreement with Energy Resources 12, L.P. (“ER12”) through its wholly-owned subsidiary, Energy Resources 12 Operating Company, LLC (the “Buyer”), to sell 50% of the Company’s then-existing interest in non-operated oil and gas properties and the related rights of the Bakken Assets for $87.5 million, subject to customary purchase price adjustments. The transaction closed on February 1, 2018, resulting in the divestiture by the Company of an approximate average 3.1% non-operated working interest in approximately 204 existing producing wells, approximately 30 wells in various stages of the drilling and completion process and additional future development locations.
On June 29, 2018, the Company entered into an agreement with Buyer to sell 99% of the Company’s remaining 50% interest in the Bakken Assets for $82.5 million, subject to customary purchase price adjustments. The transaction closed on August 31, 2018, resulting in the divestiture by the Company of an approximate average 2.7% non-operated working interest in approximately 240 existing producing wells, 20 wells in various stages of the drilling and completion process and additional future development locations. The accompanying combined statements of revenues and direct operating expenses reflect the portion of the Bakken Assets applicable to the interests acquired by Buyer on August 31, 2018 (the “Properties”).
Revenues in the accompanying combined statements of revenues and direct operating expenses are recognized on the sales method. Direct operating expenses are recognized on the accrual method and consist of monthly operator overhead and other direct costs of operating the Properties. Included in direct operating costs are costs associated with field operating expenses, workovers and monthly operator overhead.
The accompanying audited statements of revenues and direct operating expenses were derived from Enerplus’s historical accounting records prior to the purchase of the Bakken Assets by the Company. The combined statements of revenues and direct operating expenses represent the revenues and direct operating expenses for the Properties for the period of Enerplus ownership (January 1, 2016 to December 29, 2016) and for the period of the Company’s ownership (December 30, 2016 to June 30, 2018).
The combined statements of revenues and direct operating expenses vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Properties including, but not limited to, general and administrative expenses and interest expense. These costs were not separately allocated to the Properties in the accounting records of the Company. In addition, these allocations, if made using historical general and administrative and debt structures, would not produce allocations that would be indicative of the historical performance of the Properties had it been a Buyer property due to the differing size, structure, operations and accounting policies of the Company and Buyer. The accompanying financial statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs that Buyer will incur upon the allocation of the purchase price paid for the Properties. The accompanying statements also do not include provisions for federal or state income taxes.
Furthermore, no balance sheet has been presented for the Properties because the acquired properties were not accounted for as a separate subsidiary or division of the Company and complete financial statements are not available, nor has information about the Properties’ operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical statements of revenues and direct operating expenses of the Properties are presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission (‘‘SEC’’) Regulation S-X.
These statements of revenues and direct operating expenses are not indicative of the results of operations for the Properties on a go forward basis.
Note 2. Summary of Significant Accounting Policies
Use of Estimates
The combined statements of revenues and direct operating expenses are derived from the historical operating statements of the operators of the Properties for the Company and Enerplus. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the respective reporting periods. Actual results could be different from those estimates.
Revenue Recognition
Total revenues in the accompanying financial statements include the sale of crude oil, natural gas and natural gas liquids (“NGL”), net of royalties. The Company recognizes revenues when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. Oil and gas revenues included in these statements are recorded on the sales method, under which revenues are based on the oil, natural gas liquids and natural gas delivered rather than the net revenue interest share of oil and gas produced. There were no significant imbalances with other revenue interest owners during the six months ended June 30, 2018 and the years ended December 31, 2017 and 2016.
Direct Operating Expenses
Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Properties. The direct operating expenses include lease operating, production and ad valorem taxes, exploration costs, and processing and transportation expenses. Lease operating expenses include lifting costs, well repair expenses, facility maintenance expenses, well workover costs and other field-related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment and facilities directly related to oil and gas production activities.
Note 3. Contingencies
The activities of the Properties may become subject to potential claims and litigation in the normal course of operations. The Company is not aware of any liability related to any pending or threatened litigation that could have a material adverse effect on the operations or financial results of the Properties.
Note 4. Subsequent Events
Management has evaluated subsequent events through September 5, 2018, the date the accompanying combined statements of revenue and direct operating expenses were available to be issued, and is not aware of any events that have occurred that require adjustments to or disclosure in these financial statements.
Note 5. Supplemental Oil and Natural Gas Reserve Information (Unaudited)
The following unaudited information regarding the Properties’ oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements required by the Securities and Exchange Commission and the Financial Accounting Standards Board. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry
as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. “Revisions of previous estimates” in the table below represent changes in previous reserve estimates, either upward or downward, resulting from a change in economic factors, such as commodity prices, operating costs or development costs, or resulting from information obtained from the Partnership’s production history.
Reserve Quantity Information
Below are the net quantities of net proved developed and undeveloped reserves and proved developed reserves of the Properties:
For the year ended December 31, 2017 | For the year ended December 31, 2016 | |||||||||||||||||||||||||||||||
Oil (Bbls) | Gas (Mcf) | NGL (Bbls) | Total (BOE) | Oil (Bbls) | Gas (Mcf) | NGL (Bbls) | Total (BOE) | |||||||||||||||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||||||||||||||||||
Beginning of period | 13,707,347 | 8,122,302 | 1,225,561 | 16,286,625 | 798,543 | 807,585 | 107,641 | 1,040,782 | ||||||||||||||||||||||||
Purchase of mineral in place | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Extensions, discoveries and other additions | 22,729 | 6,964 | 1,662 | 25,552 | 12,251,740 | 6,819,056 | 1,039,554 | 14,427,803 | ||||||||||||||||||||||||
Revisions of previous estimates | (3,821,478 | ) | (3,049,387 | ) | (495,249 | ) | (4,824,958 | ) | 885,849 | 682,284 | 105,075 | 1,104,638 | ||||||||||||||||||||
Production | (292,642 | ) | (174,953 | ) | (24,432 | ) | (346,233 | ) | (228,785 | ) | (186,623 | ) | (26,709 | ) | (286,598 | ) | ||||||||||||||||
End of period | 9,615,956 | 4,904,926 | 707,542 | 11,140,986 | 13,707,347 | 8,122,302 | 1,225,561 | 16,286,625 | ||||||||||||||||||||||||
Proved developed reserves: | ||||||||||||||||||||||||||||||||
Beginning of period | 1,641,202 | 1,416,482 | 201,402 | 2,078,684 | 798,543 | 807,585 | 107,641 | 1,040,782 | ||||||||||||||||||||||||
Purchase of mineral in place | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Extensions, discoveries and other additions | 706,069 | 206,059 | 35,932 | 776,344 | 185,595 | 113,236 | 15,395 | 219,862 | ||||||||||||||||||||||||
Revisions of previous estimates | (2,005 | ) | 26,127 | 17,822 | 20,172 | 885,849 | 682,284 | 105,075 | 1,104,638 | |||||||||||||||||||||||
Production | (292,642 | ) | (174,953 | ) | (24,432 | ) | (346,233 | ) | (228,785 | ) | (186,623 | ) | (26,709 | ) | (286,598 | ) | ||||||||||||||||
End of period | 2,052,624 | 1,473,715 | 230,724 | 2,528,967 | 1,641,202 | 1,416,482 | 201,402 | 2,078,684 | ||||||||||||||||||||||||
In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Properties’ reserves are valued using the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period.
The oil and natural gas prices used in computing the Properties’ reserves as of January 1, 2018 were $51.34 per barrel of oil and $2.98 per Mcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Properties’ reserves as of January 1, 2018 were $45.49 per barrel of oil, $2.13 per Mcf of natural gas and $15.66 per barrel of NGL.
The oil and natural gas prices used in computing the Properties’ reserves as of January 1, 2017 were $42.75 per barrel of oil and $2.48 per Mcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Properties’ reserves as of January 1, 2017 were $35.25 per barrel of oil, $2.11 per Mcf of natural gas and $11.78 per barrel of NGL.
The oil, natural gas and NGL prices used in computing the Properties’ reserves as of January 1, 2016 were $50.28 per barrel of oil and $2.58 per Mcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Properties’ reserves as of January 1, 2016 were $42.78 per barrel of oil, ($0.42) per Mcf of natural gas and $6.42 per barrel of NGL.
Standardized Measure of Discounted Future Net Cash Flows
Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.
The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC, and as such, do not necessarily reflect expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.
December 31, 2017 | December 31, 2016 | |||||||
Future cash inflows | $ | 457,882,549 | $ | 514,761,123 | ||||
Future production costs | (147,326,018 | ) | (191,104,888 | ) | ||||
Future development costs | (57,864,366 | ) | (73,886,700 | ) | ||||
Future net cash flows | 252,692,165 | 249,769,535 | ||||||
10% annual discount | (150,823,925 | ) | (163,744,753 | ) | ||||
Standardized measure of discounted future net cash flows | $ | 101,868,240 | $ | 86,024,782 | ||||
Changes in the standardized measure of discounted future net cash flows are as follows:
For the year ended December 31, 2017 | For the year ended December 31, 2016 | |||||||
Standardized measure at beginning of period | $ | 86,024,783 | $ | 12,223,615 | ||||
Changes resulting from: | ||||||||
Acquisition of reserves | - | - | ||||||
Sales of oil, natural gas and NGLs, net of production costs | (10,368,764 | ) | (5,490,616 | ) | ||||
Net changes in prices and production costs | 37,523,597 | (2,701,200 | ) | |||||
Development costs incurred during the period | 11,118,756 | 1,490,491 | ||||||
Revisions of previous estimates | (38,452,466 | ) | 154,389,193 | |||||
Change in estimated future development costs | 16,022,334 | (73,886,701 | ) | |||||
Standardized measure of discounted future net cash flows | $ | 101,868,240 | $ | 86,024,782 | ||||
Energy Resources 12, L.P.
Unaudited Pro Forma Condensed Combined Financial Statements
Introduction
On February 1, 2018, Energy Resources 12 Operating Company, LLC (“Buyer”), a wholly-owned subsidiary of Energy Resources 12, L.P. (the “Partnership”), closed on the purchase of certain interests (“Acquisition No. 1”) in non-operated oil and gas properties and related rights of Bruin E&P Non-Op Holdings, LLC (“Seller”), which at closing represented an approximate average 3.1% non-operated working interest in approximately 204 existing producing wells, 30 wells in various stages of the drilling and completion process, and additional future development locations, predominantly in the counties of McKenzie, Dunn, McLean and Mountrail, North Dakota (collectively, the “Bakken Assets”). The purchase price for Acquisition No. 1 was approximately $87.5 million and was funded using proceeds from the Partnership’s best-efforts offering, proceeds from an unsecured term loan of $25.0 million, and an advance from a member of Energy Resources 12 GP, LLC, the general partner of the Partnership (“General Partner”), of $7.0 million. The advance from a member of the General Partner was repaid in full in May 2018. As of June 30, 2018, the outstanding balance of the unsecured term loan was $15.0 million.
Since closing on Acquisition No. 1, the Partnership participated in the drilling of 55 wells, of which 36 have been completed and 19 wells are in various stages of completion at June 30, 2018. As of June 30, 2018, the Partnership owned an approximate 2.7% non-operated working interest in 240 currently producing wells, 19 wells in various stages of the drilling and completion process, and additional future development locations in the Bakken Assets.
On June 29, 2018, the Buyer entered into a purchase and sale agreement with Seller for the potential purchase of an additional approximate 2.7% non-operated working interest in the Bakken Assets (“Acquisition No. 2”). On August 31, 2018, the Buyer closed on the purchase of Acquisition No. 2. The purchase price for Acquisition No. 2 was $82.5 million, subject to customary adjustments, and was funded using proceeds from the Partnership’s best-efforts offering and proceeds from a line of credit of $60.0 million. With the closing of Acquisition No. 2, the Partnership increased its non-operated working interest in the Bakken Assets to a total of approximately 5.4%.
The following unaudited pro forma condensed combined financial statements have been prepared to give pro forma effect to Acquisition No. 1 and Acquisition No. 2, which have been accounted for as asset purchases, as if the acquisitions and the related financing transactions, consisting of the Partnership’s ongoing public offering of the Partnership’s common units and the issuances of debt, had occurred on the dates indicated.
The unaudited pro forma condensed combined financial statements include a balance sheet as of June 30, 2018 and statements of operations for the year ended December 31, 2017 and the six-month period ended June 30, 2018. The unaudited pro forma condensed combined balance sheet was derived from the historical unaudited balance sheet of the Partnership as of June 30, 2018. The pro forma condensed combined statements of operations were derived from the historical audited financial statements of the Partnership for the year ended December 31, 2017, the historical unaudited financial statements of the Partnership for the six months ended June 30, 2018 and from the historical financial statements of Seller.
The unaudited pro forma condensed combined balance sheet gives effect to Acquisition No. 1 and Acquisition No. 2 and the related financing transactions of each acquisition as if they occurred on June 30, 2018. The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2017 and for the six-month period ended June 30, 2018 give effect to Acquisition No. 1 and Acquisition No. 2 and the related financing transactions of each acquisition as if they occurred on January 1, 2017.
The unaudited pro forma condensed combined financial statements and the accompanying unaudited pro forma notes should be read in conjunction with the Partnership’s historical financial statements and related notes for the year ended December 31, 2017, and for the six-month period ended June 30, 2018, including “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, which are included in this Prospectus Supplement No. 9, together with (a) the audited Combined Statements of Revenues and Direct Operating Expenses of Properties Acquired by a Subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC under Agreement dated June 29, 2018, which are included in this Prospectus Supplement No. 9, and (b) the audited Combined Statements of Revenues and Direct Operating
Expenses of Properties under Contract for Purchase by a Subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC under Agreement dated November 21, 2017, which are included in this Prospectus Supplement No. 9.
The unaudited pro forma condensed combined financial statements presented herein are based on the assumptions and adjustments described in the accompanying unaudited pro forma notes. The unaudited pro forma condensed combined financial statements are presented for illustrative purposes and are not indicative of what the financial position might have been or what results of operations might have been achieved had the acquisitions and related transactions occurred as of the dates indicated or the financial position or results of operations that might be achieved for any future periods.
Energy Resources 12, L.P.
Unaudited Pro Forma Condensed Combined Balance Sheet
June 30, 2018
Energy Resources 12, L.P. (Historical) | Pro Forma Adjustments | Notes | Energy Resources 12, L.P. Pro Forma as Adjusted | ||||||||||
| (1) | |||||||||||||
Assets | |||||||||||||
Current assets | |||||||||||||
Cash | $ | 11,881,132 | $ | (78,375,000 | ) | (A) | $ | 8,506,132 | |||||
| 60,000,000 | (B) | ||||||||||||
| 15,000,000 | (C) | ||||||||||||
Oil, natural gas and natural gas liquids revenue receivable | 3,881,168 | - | 3,881,168 | ||||||||||
Deposit for potential acquisition | 4,125,000 | (4,125,000 | ) | (A) | - | ||||||||
Deferred acquisition costs | 4,125,981 | (4,125,981 | ) | (A) | - | ||||||||
Total current assets | 24,013,281 | (11,625,981 | ) | 12,387,300 | |||||||||
Oil, natural gas and natural gas liquids interests, net | 91,234,376 | 82,500,000 | (A) | 178,000,357 | |||||||||
| 4,265,981 | (A) | ||||||||||||
Total assets | $ | 115,247,657 | $ | 75,140,000 | $ | 190,387,657 | |||||||
Liabilities | |||||||||||||
Term loan | $ | 15,000,000 | $ | - | $ | 15,000,000 | |||||||
Due to related parties | 4,474,698 | - | 4,474,698 | ||||||||||
Accounts payable and accrued expenses | 1,616,021 | - | 1,616,021 | ||||||||||
Total current liabilities | 21,090,719 | - | 21,090,719 | ||||||||||
Revolving credit facility | - | 60,000,000 | (B) | 60,000,000 | |||||||||
Asset retirement obligation | 141,768 | 140,000 | (A) | 281,768 | |||||||||
Total liabilities | 21,232,487 | 60,140,000 | 81,372,487 | ||||||||||
Partners' Equity | |||||||||||||
Limited partners' capital | 94,015,385 | 15,000,000 | (C) | 109,015,385 | |||||||||
General partners' capital | (215 | ) | - | (215 | ) | ||||||||
Total Partners' Equity | 94,015,170 | 15,000,000 | 109,015,170 | ||||||||||
Total Liabilities and Partners' Equity (Deficit) | $ | 115,247,657 | $ | 75,140,000 | $ | 190,387,657 | |||||||
(1) Balance sheet amounts obtained from the issued, unaudited financial statements of Energy Resources 12, L.P. for the six months ended June 30, 2018. | |||||||||||||
See accompanying notes to unaudited pro forma condensed combined financial statements
Energy Resources 12, L.P.
Unaudited Pro Forma Condensed Combined Statement of Operations
For the Year Ended December 31, 2017
Energy Resources 12, L.P. Historical | Acquisition No. 1 Historical | Acquisition No. 2 Historical | Pro Forma Adjustments | Notes | Energy Resources 12, L.P. Pro Forma as Adjusted | ||||||||||||||||
| (1) | (2) | (3) | |||||||||||||||||||
Revenue | |||||||||||||||||||||
Oil, natural gas and natural gas liquids revenues | $ | - | $ | 14,816,295 | $ | 14,668,131 | $ | - | $ | 29,484,426 | |||||||||||
Operating costs and expenses | |||||||||||||||||||||
Production expenses | - | 4,342,795 | 4,299,367 | - | 8,642,162 | ||||||||||||||||
Transaction costs | 525,000 | - | - | - | 525,000 | ||||||||||||||||
General and administrative expenses | 99,410 | - | - | 1,218,599 | (E) | 1,318,009 | |||||||||||||||
Depreciation, depletion and amortization | - | - | - | 3,284,571 | (F) | 6,442,161 | |||||||||||||||
| 3,157,590 | (G) | ||||||||||||||||||||
Total operating costs and expenses | 624,410 | 4,342,795 | 4,299,367 | 7,660,760 | 16,927,332 | ||||||||||||||||
Operating income | (624,410 | ) | 10,473,500 | 10,368,764 | (7,660,760 | ) | 12,557,094 | ||||||||||||||
Interest income (expense), net | 114,163 | - | - | (100,000 | ) | (H) | (3,371,143 | ) | |||||||||||||
| (3,385,306 | ) | (H) | |||||||||||||||||||
Net income (loss) | $ | (510,247 | ) | $ | 10,473,500 | $ | 10,368,764 | $ | (11,146,066 | ) | $ | 9,185,951 | |||||||||
Basic and diluted net income (loss) per common unit | $ | (0.48 | ) | $ | 1.54 | ||||||||||||||||
Weighted average common units outstanding - basic and diluted | 1,067,941 | 4,885,824 | (I) | 5,953,765 | |||||||||||||||||
(1) Statement of operations amounts obtained from the audited consolidated financial statements of Energy Resources 12, L.P. for the year ended December 31, 2017. |
|
(2) Statement of operations amounts obtained from the Combined Statements of Revenues and Direct Operating Expenses of Properties under Contract for Purchase by a subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC under Agreement dated November 21, 2017 and from historical revenue statements and joint interest billings obtained from Seller for the three month period from October 1, 2017 to December 31, 2017. |
|
(3) Statement of operations amounts obtained from the Combined Statements of Revenues and Direct Operating Expenses of Properties Acquired by a subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC under Agreement dated June 29, 2018. |
See accompanying notes to unaudited pro forma condensed combined financial statements
Energy Resources 12, L.P.
Unaudited Pro Forma Condensed Combined Statement of Operations
For the Six Months Ended June 30, 2018
Energy Resources 12, L.P. Historical | Acquisition No. 1 Historical | Acquisition No. 2 Historical | Pro Forma Adjustments | Notes | Energy Resources 12, L.P. Pro Forma as Adjusted | ||||||||||||||||
| (1) | (2) | (2) | |||||||||||||||||||
Revenue | |||||||||||||||||||||
Oil, natural gas and natural gas liquids revenues | $ | 11,028,175 | $ | 12,729,593 | $ | 12,602,297 | $ | (11,028,175 | ) | (D) | $ | 25,331,890 | |||||||||
Operating costs and expenses | |||||||||||||||||||||
Production expenses | 3,207,153 | 3,689,206 | 3,652,314 | (3,207,153 | ) | (D) | 7,341,520 | ||||||||||||||
General and administrative expenses | 744,034 | - | - | - | 744,034 | ||||||||||||||||
Depreciation, depletion and amortization | 2,016,079 | - | - | (2,016,079 | ) | (D) | 4,419,828 | ||||||||||||||
| 2,358,745 | (F) | ||||||||||||||||||||
| 2,061,083 | (G) | ||||||||||||||||||||
Total operating costs and expenses | 5,967,266 | 3,689,206 | 3,652,314 | (803,404 | ) | 12,505,382 | |||||||||||||||
Operating income | 5,060,909 | 9,040,387 | 8,949,983 | (10,224,771 | ) | 12,826,508 | |||||||||||||||
Interest income (expense), net | (372,049 | ) | - | - | 406,862 | (H) | (1,920,012 | ) | |||||||||||||
| (1,954,825 | ) | (H) | |||||||||||||||||||
Net income (loss) | $ | 4,688,860 | $ | 9,040,387 | $ | 8,949,983 | $ | (11,772,734 | ) | $ | 10,906,496 | ||||||||||
Basic and diluted net income (loss) per common unit | $ | 1.24 | $ | 1.83 | |||||||||||||||||
Weighted average common units outstanding - basic and diluted | 3,795,001 | 2,158,764 | (I) | 5,953,765 | |||||||||||||||||
(1) Statement of operations amounts obtained from the issued, unaudited financial statements of Energy Resources 12, L.P. for the six months ended June 30, 2018. |
|
(2) Statement of operations amounts obtained from historical activity from Energy Resources 12, L.P. for five month period from February 1, 2018 to June 30, 2018 and revenue statements and joint interest billings from Seller for January 2018. |
See accompanying notes to unaudited pro forma condensed combined financial statements
Energy Resources 12, L.P.
Notes to Unaudited Pro Forma Condensed Combined Financial Statements
1. Basis of Presentation
The unaudited pro forma balance sheet gives effect to Acquisitions No. 1 and No. 2 and the related financing transactions as of June 30, 2018. The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2017 and for the six months ended June 30, 2018 give effect to Acquisitions No. 1 and No. 2 and the related financing transactions as if they occurred on January 1, 2017.
The unaudited pro forma condensed combined financial statements were derived by adjusting the Partnership’s historical financial statements for Acquisitions No. 1 and No. 2 and related transactions. The unaudited pro forma condensed combined financial statements are provided for informational purposes only and are not indicative of the Partnership’s financial position or results of operations had the transaction been consummated on the dates indicated or financial position or results of operations for any future period or date.
The unaudited pro forma condensed combined financial statements and the accompanying unaudited pro forma notes should be read in conjunction with the Partnership’s historical financial statements and related notes for the year ended December 31, 2017, and for the six-month period ended June 30, 2018, including “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, together with (a) the audited Combined Statements of Revenues and Direct Operating Expenses of Properties Acquired by a Subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC under Agreement dated June 29, 2018, which are included in this Prospectus Supplement No. 9, and (b) the audited Combined Statements of Revenues and Direct Operating Expenses of Properties under Contract for Purchase by a Subsidiary of Energy Resources 12, L.P. from Bruin E&P Non-Op Holdings, LLC under Agreement dated November 21, 2017, which are included in this Prospectus Supplement No. 9.
2. Proved Reserves and Purchase Price Allocation
The acquisitions qualify as asset purchases under the Financial Accounting Standards Board’s Accounting Standards Update (“ASU”) 2017-01. As such, the Partnership has allocated the purchase price of the acquired assets of Acquisitions No. 1 ($90.2 million, after customary post-closing adjustments and acquisition costs) and No. 2 ($86.8 million, after estimated customary post-closing adjustments and acquisition costs) based on the asset’s relative fair value. The purchase prices of $90.2 million and $86.8 million are reflected in the accompanying pro forma condensed combined balance sheet as Oil, natural gas and NGL interests, net, based on the successful efforts method of accounting. For purposes of estimating depreciation, depletion and amortization in the accompanying unaudited pro forma condensed combined statements of operations, the purchase prices have been allocated to oil and gas properties on a combined basis using estimates of reserves. The purchase price allocation for Acquisition No. 2 is preliminary and is subject to customary adjustments.
3. Pro Forma Adjustments
The pro forma adjustments made herein are based upon management’s preliminary estimates and assumptions that are subject to finalization. The final allocation may differ materially from the estimates reflected in these pro forma condensed combined financial statements.
Adjustments to the pro forma condensed combined balance sheet
| (A) | Reflects the cash consideration for Acquisition No. 2 working interests and anticipated purchase price allocation, subject to customary adjustments, including estimated acquisition costs of $4.1 million for Acquisition No. 2 and the estimated asset retirement obligation for Acquisition No. 2 of approximately $0.1 million. Deferred acquisition costs related to Acquisition No. 2 of $4.1 million have been capitalized and reclassed to be included as part of the asset purchase price. Also reflects $4.1 million in cash deposit paid in June 2018 applied to the purchase price at closing for Acquisition No. 2. |
| (B) | Reflects borrowing of $60.0 million from the $60.0 million revolving credit facility entered into by the Partnership in August 2018 used to fund Acquisition No. 2. |
| (C) | Reflects a portion of the net cash received with respect to the common units issued in a public offering of common units representing limited partner interests in the Partnership subsequent to the unaudited pro forma condensed combined balance sheet date of June 30, 2018, and before the filing of these pro forma financial statements. During this period, the Partnership sold approximately 0.8 million common units at $20 per common unit, resulting in approximately $15.9 million in gross proceeds to the Partnership, and $15.0 million net of selling and marketing commissions. |
Adjustments to the pro forma condensed combined statements of operations
| (D) | Reflects the elimination of the Partnership’s historical revenues, production expenses and depreciation, depletion and amortization related to Acquisition No. 1 for the five-month period from February 1, 2018 to June 30, 2018. |
| (E) | Reflects general and administrative expenses for the period presented to reflect costs associated with being a public partnership and owning operating assets. These expenses include the annual management fee, reporting, accounting and legal expenses. The annual management fee is 0.5% of the total gross equity proceeds raised in the Partnership’s best-efforts offering. |
| (F) | Reflects depletion calculated by allocation of the total purchase price of Acquisition No. 1 to combined estimates of oil and gas reserves acquired based on historical reserve information and production quantities for each of the periods presented using the successful efforts method of accounting. |
| (G) | Reflects depletion calculated by allocation of the total purchase price of Acquisition No. 2 to combined estimates of oil and gas reserves acquired based on historical reserve information and production quantities for each of the periods presented using the successful efforts method of accounting. |
| (H) | Reflects (i) interest expense incurred on the $15.0 million outstanding at June 30, 2018, at an average annual interest rate of 3.11% for the year ended December 31, 2017 and 3.81% for the six months ended June 30, 2018; (ii) interest expense on the outstanding balance of the revolving credit facility described in Adjustment (B) of $60.0 million for the year ended December 31, 2017 and six months ended June 30, 2018 at an average annual interest rate of 4.86% and 5.56%, respectively; and (iii) reversal of applicable interest expense and income in the historical Partnership financial statements. |
| (I) | Reflects the increase in weighted average shares for the assumed acquisition date of January 1, 2017 and the shares issued subsequent to June 30, 2018 discussed in Adjustment (C). |
