UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
| | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended
| | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _______ TO _______ |
Commission File Number
(Exact name of registrant as specified in its charter)
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| (State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) |
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| (Address of principal executive offices) | (Zip Code) |
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(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol | Name of each exchange on which registered |
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer ☐ | Accelerated filer ☐ | |
| | Smaller reporting company | |
| Emerging growth company |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐
As of November 12, 2021, the Partnership had
Energy Resources 12, L.P.
Form 10-Q
Index
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PART I. FINANCIAL INFORMATION |
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Item 1. |
Consolidated Financial Statements (Unaudited) |
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Consolidated Balance Sheets – September 30, 2021 and December 31, 2020 |
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Consolidated Statements of Operations – Three and nine months ended September 30, 2021 and 2020 |
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Consolidated Statements of Cash Flows – Nine months ended September 30, 2021 and 2020 |
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Item 2. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 3. |
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Item 4. |
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PART II. OTHER INFORMATION |
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Item 1. |
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Item 1A. |
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Item 2. |
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Item 3. |
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Item 4. |
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Item 5. |
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Item 6. |
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Energy Resources 12, L.P.
Consolidated Balance Sheets
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September 30, |
December 31, |
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2021 |
2020 |
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(unaudited) |
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Assets |
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Cash and cash equivalents |
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Accounts receivable and other current assets |
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Total Current Assets |
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| Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $ |
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Total Assets |
$ | $ | ||||||
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Liabilities |
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Accounts payable and accrued expenses |
$ | $ | ||||||
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Derivative liability |
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Total Current Liabilities |
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Asset retirement obligations |
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Total Liabilities |
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Partners’ Equity |
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General partner's interest |
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Total Partners’ Equity |
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Total Liabilities and Partners’ Equity |
$ | $ | ||||||
See notes to consolidated financial statements.
Energy Resources 12, L.P.
Consolidated Statements of Operations
(Unaudited)
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Three Months Ended |
Three Months Ended |
Nine months ended |
Nine months ended |
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September 30, 2021 |
September 30, 2020 |
September 30, 2021 |
September 30, 2020 |
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Revenues |
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Oil |
$ | $ | $ | $ | ||||||||||||
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Natural gas |
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Natural gas liquids |
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Total revenue |
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Operating costs and expenses |
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Production expenses |
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Production taxes |
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General and administrative expenses |
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Depreciation, depletion, amortization and accretion |
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Total operating costs and expenses |
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Operating income (loss) |
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Interest income (expense), net |
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Gain (loss) on derivatives |
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Total other income (expense), net |
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Net income (loss) |
$ | $ | ( |
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Basic and diluted net income (loss) per common unit |
$ | $ | ( |
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Weighted average common units outstanding - basic and diluted |
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See notes to consolidated financial statements.
Energy Resources 12, L.P.
Consolidated Statements of Partners’ Equity
(Unaudited)
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Limited Partner |
General Partner |
Total Partners' |
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Common Units |
Amount |
Amount |
Equity |
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Balances - December 31, 2019 |
$ | $ | ( |
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| Distributions declared and paid to common units ($ |
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Net income - three months ended March 31, 2020 |
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Balances - March 31, 2020 |
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| Distributions declared and paid to common units ($ |
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Net loss - three months ended June 30, 2020 |
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Balances - June 30, 2020 |
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| Distributions declared and paid to common units ($ |
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Net loss - three months ended September 30, 2020 |
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Balances - September 30, 2020 |
$ | $ | ( |
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Balances - December 31, 2020 |
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| Distributions declared and paid to common units ($ |
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Net income - three months ended March 31, 2021 |
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Balances - March 31, 2021 |
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| Distributions declared and paid to common units ($ |
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Net income - three months ended June 30, 2021 |
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Balances - June 30, 2021 |
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| Distributions declared and paid to common units ($ |
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Net income - three months ended September 30, 2021 |
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Balances - September 30, 2021 |
$ | $ | ( |
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See notes to consolidated financial statements.
Energy Resources 12, L.P.
Consolidated Statements of Cash Flows
(Unaudited)
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Nine months ended |
Nine months ended |
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September 30, 2021 |
September 30, 2020 |
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Cash flow from operating activities: |
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Net income (loss) |
$ | $ | ( |
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Adjustments to reconcile net income (loss) to cash from operating activities: |
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Depreciation, depletion, amortization and accretion |
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Gain on mark-to-market of derivatives |
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Changes in operating assets and liabilities: |
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Accounts receivable and other current assets |
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Accounts payable and accrued expenses |
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Net cash flow provided by operating activities |
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Cash flow from investing activities: |
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Cash paid for acquisition of oil and natural gas properties |
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Additions to oil and natural gas properties |
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Net cash flow used in investing activities |
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Cash flow from financing activities: |
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Distributions paid to limited partners |
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Net cash flow used in financing activities |
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Increase (decrease) in cash and cash equivalents |
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Cash and cash equivalents, beginning of period |
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Cash and cash equivalents, end of period |
$ | $ | ||||||
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Supplemental non-cash information: |
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Accrued capital expenditures related to additions to oil and natural gas properties |
$ | $ | ||||||
See notes to consolidated financial statements.
Energy Resources 12, L.P.
Notes to Consolidated Financial Statements
September 30, 2021
(Unaudited)
Note 1. Partnership Organization
Energy Resources 12, L.P. (together with its wholly-owned subsidiary, the “Partnership”) is a
As of September 30, 2021, the Partnership owned an approximate
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.
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, 2020 financial statements included in its 2020 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2021 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2021.
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.
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.
Revenue Recognition
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. 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. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts Receivable and other current assets in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
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.
Fair Value of Other Financial Instruments
The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.
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 (Loss) Per Common Unit
Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (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 three and nine months ended September 30, 2021 and 2020. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights, as defined below, are not included in net income (loss) per common unit until such time that it is probable Payout (as discussed in Note 7) will occur.
Note 3. Oil and Gas Investments
On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Bakken Assets for approximately $
From September 1, 2017, the effective date of Acquisition No. 1, to September 30, 2021, the Partnership has participated in the drilling of
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:
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2021 |
2020 |
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Balance at January 1 |
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Well additions |
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Accretion |
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Revisions |
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Balance at September 30 |
$ | $ | ||||||
Note 5. Risk Management
Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and the Partnership’s future earnings are subject to these risks. Periodically, the Partnership enters into derivative contracts to manage the commodity price risk on a portion of the Partnership’s anticipated future oil and gas production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations.
The Partnership did not have any outstanding derivative contracts as of September 30, 2021. As of December 31, 2020, the Partnership’s derivatives were in a loss position; therefore, a current liability of $
The Partnership did not designate its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The Partnership did not settle any contracts during the third quarters of 2021 or 2020. The following table presents settlements of matured derivative instruments and non-cash losses on open derivative instruments for the periods presented.
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Nine Months Ended |
Nine Months Ended |
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Settlement gain (loss) on matured derivatives |
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Gain on mark-to-market of derivatives |
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Gain (loss) on derivatives, net |
$ | ( |
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Settlements on matured derivatives above reflect a realized gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash, unrealized) gains above represent the change in fair value of derivative instruments which were held at period-end. Unrealized gains and losses do not represent actual settlements or payments made to or from the counterparty.
Note 6. Capital Contribution and Partners’ Equity
At inception, the General Partner and organizational limited partner made initial capital contributions totaling $
The Partnership completed its best-efforts offering of common units as of the close of business on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately
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 or 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:
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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. |
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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 months ended September 30, 2021 and 2020, the Partnership paid distributions of $
Note 7. Related Parties
The Class A voting members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer and David S. McKenney, Chief Financial Officer. Messrs. Knight and McKenney 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. The Class B non-voting members of the General Partner are affiliates of Anthony F. Keating, III and Michael J. Mallick, the Co-Chief Operating Officers of Energy 11’s general partner.
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, costs incurred in the offering of the common units and general and administrative costs. The Partnership 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 Partnership Agreement,
For the three and nine months ended September 30, 2021, approximately $
On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 that gave the Partnership access to Energy 11’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The cost sharing agreement reduced these accounting and asset management costs to the Partnership, as these shared day-to-day costs were split evenly between the two partnerships. The shared costs were based on actual costs incurred with no mark-up or profit to the Partnership. Any other direct third-party costs were paid by the party receiving the services. For the three and nine months ended September 30, 2020, approximately $
On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and Energy 11, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. The ASA became effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or Energy 11 ceases to own its respective oil and natural gas assets. Provided the ASA is not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect.
Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits – including those of the president of Energy 11’s general partner (of which the General Partner agreed to pay as the president is an employee of the Administrator), rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the three and nine months ended September 30, 2021, approximately $
Note 8. Subsequent Events
In October 2021, the Partnership declared and paid $
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Certain statements within this report 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:
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the easing of COVID-19 and the return to pre-existing supply and demand conditions following the ultimate recovery therefrom; |
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intentions of the Partnership’s operators with regard to the drilling programs and the possible curtailment or shut-in of the Partnership’s wells; |
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references to future success in the Partnership’s drilling and marketing activities; |
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the Partnership’s business strategy; |
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estimated future distributions; |
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estimated future capital expenditures; |
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sales of the Partnership’s properties and other liquidity events; |
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competitive strengths and goals; and |
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other similar matters. |
These forward-looking statements reflect the Partnership’s 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 the Partnership’s 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” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020 and the following:
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that the Partnership’s development of its properties may not be successful or that its operations on such properties may not be successful; |
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general economic, market, or business conditions; |
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changes in laws or regulations; |
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the risk that the wells in which the Partnership acquired an interest are productive, but do not produce enough revenue to return the investment made; |
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the risk that the wells the Partnership drills do not find hydrocarbons in commercial quantities or, even if commercial quantities are encountered, that actual production is lower than expected on the productive life of wells is shorter than expected; |
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current credit market conditions and the Partnership’s ability to obtain long-term financing or refinancing debt for the Partnership’s drilling and acquisition activities in a timely manner and on terms that are consistent with what the Partnership projects; |
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uncertainties concerning the price of oil and natural gas, which may decrease and remain low for prolonged periods; and |
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the risk that any hedging policy the Partnership employs to reduce the effects of changes in the prices of the Partnership’s production will not be effective. |
Although the Partnership believes the expectations reflected in such forward-looking statements are based upon reasonable assumptions, the Partnership cannot assure investors that its 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, the Partnership undertakes 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.
The following discussion and analysis should be read in conjunction with the Partnership’s Unaudited Consolidated Financial Statements and Notes thereto, appearing elsewhere in this Quarterly Report on Form 10-Q, as well as the information contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020.
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 began offering common units of limited partner interest (the “common units”) on a best-efforts basis on May 17, 2017, the date the Partnership’s initial Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and Exchange Commission. The Partnership completed its best-efforts offering on October 24, 2019. Total common units sold were approximately 11.0 million for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.
The general partner is Energy Resources 12 GP, LLC (the “General Partner”). 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 has no officers, directors or employees.
The Partnership was formed to acquire primarily oil and gas properties located onshore in the United States. On February 1, 2018, the Partnership completed its first asset purchase in the Williston Basin of North Dakota, acquiring, at closing, non-operated working interests in producing wells and in-process wells, along with additional future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”), for approximately $90.5 million. On August 31, 2018, the Partnership closed on its second asset purchase, acquiring an additional non-operated working interest in the Bakken Assets for approximately $81.3 million. Prior to these acquisitions, the Partnership owned no oil and natural gas assets. The Partnership utilized proceeds from its best-efforts offering and available financing to close on the acquisitions.
As a result of these acquisitions and completed drilling during the period of ownership, as of September 30, 2021, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.7% non-operated working interest in 388 producing wells, an estimated 2.0% non-operated working interest in 9 wells in various stages of the drilling and completion process and additional possible future development locations.
The Bakken Assets are operated by 14 third-party operators, including Devon Energy Corporation (NYSE: DVN), Marathon Oil (NYSE: MRO), EOG Resources (NYSE: EOG), Continental Resources (NYSE: CLR) and RimRock Oil and Gas.
Current Price Environment
Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Historically, world-wide oil and natural gas prices and markets have been subject to significant change and may continue to be in the future. Global macroeconomic factors contributing to uncertainty within the industry include real or perceived geopolitical risks in oil-producing regions of the world, particularly the Middle East; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; environmental and climate change regulation; actions taken by the Organization of the Petroleum Exporting Countries (“OPEC”); and the strength of the U.S. dollar in international currency markets.
The outbreak of a novel coronavirus (“COVID-19”) in China in December 2019 significantly impacted the global economy throughout 2020, and the domestic oil and gas industry was especially impacted as demand for oil, natural gas and other hydrocarbons substantially declined in March and April 2020. In addition to the outbreak of COVID-19, Saudi Arabia and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020 that ultimately led to excess crude oil and natural gas inventory and congested supply chain channels, which weighed negatively on commodity prices while demand was low. Demand for oil and natural gas began to return in the fourth quarter of 2020 as government-mandated COVID-19 restrictions eased. The increased demand and production restraint by domestic and foreign operators during 2021 have contributed to higher commodity prices, with oil prices averaging over $70 per barrel for the third quarter of 2021 and topping $80 per barrel in October 2021.
The Partnership’s revenues and cash flow from operations are highly sensitive to changes in oil and natural gas prices and to levels of production. If commodity prices significantly drop, such as the decline in the second quarter of 2020, and remain low, the Partnership will see a reduction in available capital for the development of its undrilled wellsites. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.
The following table lists average NYMEX prices for oil and natural gas for the three and nine months ended September 30, 2021 and 2020.
|
Three Months Ended September 30, |
Percent |
Nine Months Ended September 30, |
Percent |
|||||||||||||||||||||
|
2021 |
2020 |
Change |
2021 |
2020 |
Change |
|||||||||||||||||||
|
Average market closing prices (1) |
||||||||||||||||||||||||
|
Oil (per Bbl) |
$ | 70.52 | $ | 40.91 | 72.4 | % | $ | 65.04 | $ | 38.22 | 70.2 | % | ||||||||||||
|
Natural gas (per Mcf) |
$ | 4.35 | $ | 2.00 | 117.5 | % | $ | 3.61 | $ | 1.87 | 93.0 | % | ||||||||||||
|
(1) |
Based on average NYMEX futures closing prices (oil) and NYMEX/Henry Hub spot prices (natural gas) |
Results of Operations
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 (“NGL” or “NGLs”), (3) production costs per BOE and (4) capital expenditures.
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 and nine months ended September 30, 2021 and 2020. The effect of the outbreak of COVID-19 during the first and second quarters of 2020 had a significant negative impact to the Partnership’s results from operations; as a result, the periods presented in the table below may not be directly comparable.
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||||||||||||||
|
2021 |
Percent of Revenue |
2020 |
Percent of Revenue |
Percent |
2021 |
Percent of Revenue |
2020 |
Percent of Revenue |
Percent |
|||||||||||||||||||||||||||
|
Total revenues |
$ | 13,903,395 | 100.0 | % | $ | 7,903,439 | 100.0 | % | 75.9 | % | $ | 42,986,310 | 100.0 | % | $ | 23,025,766 | 100.0 | % | 86.7 | % | ||||||||||||||||
|
Production expenses |
4,742,089 | 34.1 | % | 3,353,888 | 42.4 | % | 41.4 | % | 13,686,922 | 31.8 | % | 11,093,766 | 48.2 | % | 23.4 | % | ||||||||||||||||||||
|
Production taxes |
1,034,541 | 7.4 | % | 666,258 | 8.4 | % | 55.3 | % | 3,291,710 | 7.7 | % | 1,956,851 | 8.5 | % | 68.2 | % | ||||||||||||||||||||
|
Depreciation, depletion, amortization and accretion |
3,366,070 | 24.2 | % | 3,438,939 | 43.5 | % | -2.1 | % | 11,287,314 | 26.3 | % | 10,220,331 | 44.4 | % | 10.4 | % | ||||||||||||||||||||
|
General and administrative expenses |
530,996 | 3.8 | % | 521,267 | 6.6 | % | 1.9 | % | 1,818,524 | 4.2 | % | 1,844,168 | 8.0 | % | -1.4 | % | ||||||||||||||||||||
|
Sold production (BOE): |
||||||||||||||||||||||||||||||||||||
|
Oil |
155,294 | 187,371 | -17.1 | % | 555,140 | 590,495 | -6.0 | % | ||||||||||||||||||||||||||||
|
Natural gas |
46,584 | 37,667 | 23.7 | % | 160,559 | 104,476 | 53.7 | % | ||||||||||||||||||||||||||||
|
Natural gas liquids |
46,048 | 35,747 | 28.8 | % | 156,184 | 95,848 | 62.9 | % | ||||||||||||||||||||||||||||
|
Total |
247,926 | 260,785 | -4.9 | % | 871,883 | 790,819 | 10.3 | % | ||||||||||||||||||||||||||||
|
Average sales price per unit: |
||||||||||||||||||||||||||||||||||||
|
Oil (per Bbl) |
$ | 68.67 | $ | 38.60 | 77.9 | % | $ | 62.55 | $ | 36.12 | 73.2 | % | ||||||||||||||||||||||||
|
Natural gas (per Mcf) |
4.97 | 1.49 | 233.6 | % | 3.92 | 1.62 | 142.0 | % | ||||||||||||||||||||||||||||
|
Natural gas liquids (per Bbl) |
40.14 | 9.35 | 329.3 | % | 28.70 | 7.13 | 302.5 | % | ||||||||||||||||||||||||||||
|
Combined (per BOE) |
56.08 | 30.31 | 85.0 | % | 49.30 | 29.12 | 69.3 | % | ||||||||||||||||||||||||||||
|
Average unit cost per BOE: |
||||||||||||||||||||||||||||||||||||
|
Production expenses |
19.13 | 12.86 | 48.8 | % | 15.70 | 14.03 | 11.9 | % | ||||||||||||||||||||||||||||
|
Production taxes |
4.17 | 2.55 | 63.5 | % | 3.78 | 2.47 | 53.0 | % | ||||||||||||||||||||||||||||
|
Depreciation, depletion, amortization and accretion |
13.58 | 13.19 | 3.0 | % | 12.95 | 12.92 | 0.2 | % | ||||||||||||||||||||||||||||
|
Capital expenditures |
$ | 638,432 | $ | 3,397,159 | $ | 3,762,339 | $ | 6,472,248 | ||||||||||||||||||||||||||||
Oil, natural gas and NGL revenues
For the three months ended September 30, 2021, revenues for oil, natural gas and NGL sales were $13.9 million. Revenues for the sale of crude oil were $10.7 million, which resulted in a realized price of $68.67 per barrel. Revenues for the sale of natural gas were $1.4 million, which resulted in a realized price of $4.97 per Mcf. Revenues for the sale of NGLs were approximately $1.8 million, which resulted in a realized price of $40.14 per BOE of production. For the three months ended September 30, 2020, revenues for oil, natural gas and NGL sales were $7.9 million. Revenues for the sale of crude oil were $7.2 million, which resulted in a realized price of $38.60 per barrel. Revenues for the sale of natural gas were $0.3 million, which resulted in a realized price of $1.49 per Mcf. Revenues for the sale of NGLs were approximately $0.3 million, which resulted in a realized price of $9.35 per BOE of production.
For the nine months ended September 30, 2021, revenues for oil, natural gas and NGL sales were $43.0 million. Revenues for the sale of crude oil were $34.7 million, which resulted in a realized price of $62.55 per barrel. Revenues for the sale of natural gas were $3.8 million, which resulted in a realized price of $3.92 per Mcf. Revenues for the sale of NGLs were approximately $4.5 million, which resulted in a realized price of $28.70 per BOE of production. For the nine months ended September 30, 2020, revenues for oil, natural gas and NGL sales were $23.0 million. Revenues for the sale of crude oil were $21.3 million, which resulted in a realized price of $36.12 per barrel. Revenues for the sale of natural gas were $1.0 million, which resulted in a realized price of $1.62 per Mcf. Revenues for the sale of NGLs were $0.7 million, which resulted in a realized price of $7.13 per BOE.
The Partnership’s results for the three and nine months ended September 30, 2021 were positively impacted by the significant increase in market prices of oil, natural gas and NGLs when compared to the same periods of 2020. Specifically, the Partnership realized increases exceeding average market gas and NGL prices in February 2021 as a result of the severe winter weather storms that resulted in power outages in Texas and other southern states. In addition, the Partnership’s realized sales price for oil have benefited from improved differentials (see below) during 2021 as the market imbalances and certain supply chain constraints that developed during the spring and summer of 2020 due to COVID-19 have eased.
The Partnership’s sold oil production was negatively impacted by COVID-19 cost-cutting measures implemented by operators of the Bakken Assets for the nine months ended September 30, 2020, as approximately 25% of the Partnership’s wells were shut in for at least a portion of the second quarter of 2020. Some operators of the Bakken Assets have cautiously resumed new drilling as commodity prices have recovered throughout 2021, but new capital investment and drilling of new wells on the Partnership’s acreage has been limited during 2021. While the Partnership’s operators did complete 14 new wells during the second quarter of 2021, new oil production from the 14 new wells has not fully offset the natural production decline of the Partnership’s wells as they age. Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following completion, then decline to more consistent levels. However, higher natural gas and NGL prices have incentivized the Partnership’s operators to improve the treatment and processing of extracted natural gas from the Bakken Assets; as a result, operators have ultimately reduced the shrink upon extraction of natural gas, which has yielded higher gas and NGL volumes during 2021, in comparison to the same period of 2020. The Partnership’s sold production for the Bakken Assets was approximately 2,700 BOE and 3,200 BOE per day for the three and nine months ended September 30, 2021, respectively, compared to 2,800 BOE and 2,900 BOE per day for the same periods of 2020.
If commodity prices fall from current levels and operators are unable to produce, process and sell oil and natural gas at economical prices, the operators of the Bakken Assets may curtail daily production, shut-in producing wells or seek other cost-cutting measures. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL production, and there can be no assurance regarding how they will produce if and when they are brought back on-line. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion on the Partnership’s investment in new wells in “Liquidity and Capital Resources” below.
Differentials
The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Bakken. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. Due to improvement in commodity prices and market-specific conditions in the Bakken during 2021, oil price differentials have improved during the three and nine months ended September 30, 2021, in comparison to the same periods of 2020, thus resulting in higher realized prices on the sale of the Partnership’s oil production.
In July 2020, the U.S. District Court for D.C. (“D.C. District Court”) ruled that the Dakota Access Pipeline, a significant pipeline that transports oil and natural gas from North Dakota fields, must suspend operations due to inadequate environmental review previously performed by the U.S. Army Corps of Engineers. In August 2020, the ruling was stayed on appeal by the U.S. Court of Appeals for the D.C. Circuit (“D.C. Appellate Court”), allowing the pipeline to operate until a further ruling was made. In January 2021, the D.C. Appellate Court affirmed the D.C. District Court’s decision. Further, in May 2021, the D.C. District Court denied an injunction that would have required a shutdown of the Dakota Access Pipeline while the U.S. Army Corps of Engineers completes its comprehensive environmental review. In June 2021, the D.C. District Court dismissed the existing claims against the Dakota Access Pipeline and its operators, but stated the plaintiffs could renew challenges against the pipeline after the U.S. Army Corps of Engineers releases its environmental review report, which is anticipated to be issued in the fall of 2022. If use of the Dakota Access Pipeline or any other pipelines servicing the region are suspended at a future date, the disruption of transporting the Partnership’s production out of North Dakota could negatively impact the Partnership’s realized sales prices, results of operations and/or cash flows.
Operating costs and expenses
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, saltwater 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 September 30, 2021 and 2020 were $4.7 million and $3.4 million, and production expenses per BOE were $19.13 and $12.86, respectively. Production expenses for the nine months ended September 30, 2021 and 2020 were $13.7 million and $11.1 million, and production expenses per BOE were $15.70 and $14.03, respectively. Production expenses per BOE increased in the three and nine months ended September 30, 2021, in comparison to the same periods of 2020, primarily due to (i) lower sold production volumes, which decreases the production base over which fixed costs are spread, and (ii) an increase in total gathering, processing and selling costs associated with the increased sale of the Partnership’s natural gas and NGL production. The production costs specific to the processing, treating and marketing of natural gas and NGLs are higher than those associated with oil, so an increase in sold natural gas and NGLs (in proportion to total sold volumes) results in a greater increase in these production expenses per BOE than the corresponding increase in production expenses for new oil production.
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. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the three months ended September 30, 2021 and 2020 were $1.0 million (7% of revenue) and $0.7 million (8% of revenue), respectively. Production taxes for the nine months ended September 30, 2021 and 2020 were $3.3 million (8% of revenue) and $2.0 million (9% of revenue), respectively. Oil production comprised approximately 63% and 64%, respectively, of the Partnership’s sold production volumes in the three and nine months ended September 30, 2021, whereas oil production comprised approximately 72% and 75%, respectively, of the Partnership’s sold production volumes in the three and nine months ended September 30, 2020.
General and administrative expenses
The principal components of general and administrative expense are accounting, legal, advisory and consulting fees. General and administrative costs for the three months ended September 30, 2021 and 2020 were $0.5 million in both periods. General and administrative costs for the nine months ended September 30, 2021 and 2020 were $1.8 million in both periods.
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 September 30, 2021 and 2020 was $3.4 million in both periods, and DD&A per BOE of production was $13.58 and $13.19, respectively. The Partnership’s DD&A for the nine months ended September 30, 2021 and 2020 was $11.3 million and $10.2 million, and DD&A per BOE of production was $12.95 and $12.92, respectively.
The increase in DD&A expense per BOE of production for the three months ended September 30, 2021, compared to same period of 2020, is primarily due to a reduction of the Partnership’s estimated proved developed and undeveloped reserves resulting from production and well performance during the first half of 2021.
Interest income (expense), net
Interest income (expense), net for the three months ended September 30, 2021 and 2020 was approximately $100 and $300, respectively. Interest income (expense), net for the nine months ended September 30, 2021 and 2020 was approximately $(600) and $30,000, respectively.
Gain (loss) on derivatives
Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations.
The Partnership did not designate its 2020 or 2021 derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The Partnership did not enter into any new contracts during the third quarter of 2021 and had no outstanding contracts at September 30, 2021. The following table presents settlements of its matured derivative instruments and the non-cash, mark-to-market gain recorded during the periods presented.
|
Nine Months Ended |
Nine Months Ended |
|||||||
|
Settlement gain (loss) on matured derivatives |
$ | (1,977,537 | ) | $ | 1,165,094 | |||
|
Gain on mark-to-market of derivatives |
594,632 | 207,327 | ||||||
|
Gain (loss) on derivatives, net |
$ | (1,382,905 | ) | $ | 1,372,421 | |||
The Partnership’s oil production contracts that expired during the nine months ended September 30, 2021 represented approximately 136,000 barrels of oil. The Partnership’s realized loss of approximately $2.0 million equated to an approximate loss of $14.49 per barrel of oil. The Partnership’s oil production contracts that expired during the nine months ended September 30, 2020 represented approximately 107,000 barrels of oil. The Partnership’s realized gain of approximately $1.2 million equated to an approximate gain of $10.89 per barrel of oil.
The mark-to-market (non-cash, unrealized) gains recorded for the nine months ended September 30, 2021 and 2020 represent the change in fair value of the Partnership’s derivative instruments held at period-end. Unrealized gains and losses do not represent actual settlements or payments made to or from the counterparty.
Supplemental Non-GAAP Measure
The Partnership uses “Adjusted EBITDAX”, defined as earnings (loss) before (i) interest income (expense), net; (ii) income taxes; (iii) depreciation, depletion, amortization and accretion; (iv) exploration expenses; and (v) (gain)/loss on the mark-to-market of derivative instruments, 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, operating income, cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. Adjusted EBITDAX is not necessarily indicative of funds available to fund the Partnership’s cash needs, including its ability to make cash distributions. Although Adjusted EBITDAX, as calculated by the Partnership, may not be comparable to Adjusted 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 Adjusted 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 Adjusted EBITDAX for the three and nine months ended September 30, 2021 and 2020.
|
Three Months Ended |
Three Months Ended |
Nine Months Ended |
Nine Months Ended |
|||||||||||||
|
Net income (loss) |
$ | 4,229,772 | $ | (76,659 | ) | $ | 11,518,338 | $ | (687,200 | ) | ||||||
|
Interest (income) expense, net |
(73 | ) | (254 | ) | 597 | (29,729 | ) | |||||||||
|
Depreciation, depletion, amortization and accretion |
3,366,070 | 3,438,939 | 11,287,314 | 10,220,331 | ||||||||||||
|
Exploration expenses |
- | - | - | - | ||||||||||||
|
Non-cash gain on mark-to-market of derivatives |
- | - | (594,632 | ) | (207,327 | ) | ||||||||||
|
Adjusted EBITDAX |
$ | 7,595,769 | $ | 3,362,026 | $ | 22,211,617 | $ | 9,296,075 | ||||||||
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” in Part I, Item 1 of this Form 10-Q.
Liquidity and Capital Resources
The Partnership’s principal sources of liquidity are cash on-hand and the cash flow generated from the properties the Partnership owns. The Partnership anticipates that cash on-hand and cash flow from operations will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below. Although the Partnership anticipates its cash on-hand and cash flow from operations to be adequate to fund its cash requirements, if market prices for oil and natural gas decline and/or production from Partnership wells is not replenished through the completion of new well investments, the Partnership’s cash flow from operations may decline. This could have a significant impact on the Partnership’s available cash on-hand, the Partnership’s ability to fund distributions to its limited partners and/or participate in future drilling programs as proposed by the operators of the Bakken Assets.
Partners’ Equity
The Partnership completed its best-efforts offering of common units on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.
Under the agreement with the Managing Dealer, the Managing Dealer received 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 the conclusion of the offering, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below).
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 or 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 months ended September 30, 2021 and 2020, the Partnership paid distributions of $0.349041 per common unit, or $3.9 million, in both periods. For the nine months ended September 30, 2021 and 2020, the Partnership paid distributions of $1.047123 per common unit, or $11.6 million, in both periods. The Partnership generated $22.3 million and $13.3 million in cash flow from operating activities for the nine months ended September 30, 2021 and 2020, respectively.
While the Partnership’s goal is to maintain a relatively stable distribution rate over the life of its program, the General Partner monitors monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations and capital expenditures for new wells. There can be no assurance as to the classification or duration of distributions at the current distribution rate of $1.40 per common unit per year. If distributions are not paid or are reduced, the difference to the current distribution rate of $1.40 per common unit will be deferred and is required to be paid before final Payout occurs, as discussed above.
Oil and Natural Gas Properties
The Partnership incurred approximately $3.8 million and $6.5 million in capital expenditures during the nine months ended September 30, 2021 and 2020. As discussed above, the Partnership has 9 wells in various stages of the drilling and completion process, and the Partnership estimates its share of capital expenditures to complete those 9 wells is less than $1 million. In addition to the estimated capital expenditures remaining for 2021 of approximately $1 to $2 million (including costs to complete the 9 in-process wells), the Partnership anticipates that it may be obligated to invest up to an additional $65 to $75 million in drilling capital expenditures from 2022 through 2026 to participate in new well development in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements or North Dakota statutes governing the Bakken Assets.
Since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict levels of future participation in the drilling and completion of new wells, the timing of such activities and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for the remainder of 2021 and into 2022. Current estimated capital expenditures could be significantly different from amounts actually invested.
The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from cash on hand and cash generated by its producing wells. If an operator elects to complete drilling or other significant capital expenditure activity and the Partnership is unable to fund the capital expenditures, the General Partner may decide to farmout the well. Also, if a well is proposed under the operating agreement for one of the properties the Partnership owns, the General Partner may elect to “non-consent” the well. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well and would be subject to a non-consent penalty.
Subsequent Events
In October 2021, the Partnership declared and paid $1.5 million, or $0.134247 per outstanding common unit, in distributions to its holders of common units.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information regarding the Partnership’s hedging programs to mitigate commodity risks is contained in Item 1 – Financial Statements (Unaudited) and Notes to Consolidated Financial Statements: Note 5. Risk Management and Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, appearing elsewhere within this Quarterly Report on Form 10-Q.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
In accordance with Exchange Act Rule 13a–15 and 15d–15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Partnership carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of September 30, 2021 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.
Change in Internal Controls Over Financial Reporting
There have not been any changes in the Partnership’s internal controls over financial reporting that occurred during the quarterly period ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
At the end of the period covered by this Quarterly Report on Form 10-Q, the Partnership was not a party to any material, pending legal proceedings.
Item 1A. Risk Factors
For a discussion of the Partnership’s potential risks and uncertainties, see the section titled “Risk Factors” in the Partnership’s 2020 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2020 Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Not applicable.
Item 3. Defaults upon Senior Securities.
Not applicable.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
Not applicable.
Item 6. Exhibits.
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Exhibit No. |
Description |
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31.1 |
Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002* |
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31.2 |
Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002* |
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32.1 |
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32.2 |
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101 |
The following materials from Energy Resources 12, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Partners’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) related notes to the consolidated financial statements, tagged as blocks of text and in detail* |
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104 |
The cover page from the Partnership’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, formatted in iXBRL and contained in Exhibit 101. |
*Filed herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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Energy Resources 12, L.P. |
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By: Energy Resources 12 G.P., LLC, its General Partner |
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By: |
/s/ Glade M. Knight |
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Glade M. Knight |
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Chief Executive Officer (Principal Executive Officer) |
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By: |
/s/ David S. McKenney |
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David S. McKenney |
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Chief Financial Officer (Principal Financial and Accounting Officer) |
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Date: November 12, 2021 |
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