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) |
(
(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 August 12, 2022, the Partnership had
Energy 11, L.P.
Form 10-Q
Index
Page Number |
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PART I. FINANCIAL INFORMATION |
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Item 1. |
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Consolidated Balance Sheets – June 30, 2022 and December 31, 2021 |
3 |
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Consolidated Statements of Operations – Three and six months ended June 30, 2022 and 2021 |
4 |
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Consolidated Statements of Partners’ Equity – Three and six months ended June 30, 2022 and 2021 |
5 |
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Consolidated Statements of Cash Flows – Six months ended June 30, 2022 and 2021 |
6 |
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7 |
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Item 2. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
15 |
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Item 3. |
24 |
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Item 4. |
24 |
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PART II. OTHER INFORMATION |
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Item 1. |
25 |
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Item 1A. |
25 |
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Item 2. |
25 |
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Item 3. |
25 |
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Item 4. |
25 |
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Item 5. |
25 |
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Item 6. |
25 |
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26 |
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Energy 11, L.P.
Consolidated Balance Sheets
June 30, |
December 31, |
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2022 |
2021 |
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(unaudited) |
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Assets |
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Cash and cash equivalents |
$ | $ | ||||||
Accounts receivable |
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Other current assets, net |
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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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Other assets |
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Total Assets |
$ | $ | ||||||
Liabilities |
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Accounts payable and accrued expenses |
$ | $ | ||||||
Derivative liability |
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Total Current Liabilities |
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Revolving credit facility |
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Asset retirement obligations |
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Derivative liability - noncurrent |
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Total Liabilities |
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Partners’ Equity |
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Limited partners' interest ( |
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General partner's interest |
( |
) | ( |
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Class B Units ( |
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Total Partners’ Equity |
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Total Liabilities and Partners’ Equity |
$ | $ |
See notes to consolidated financial statements.
Energy 11, L.P.
Consolidated Statements of Operations
(Unaudited)
Three Months Ended |
Three Months Ended |
Six Months Ended |
Six Months Ended |
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June 30, 2022 |
June 30, 2021 |
June 30, 2022 |
June 30, 2021 |
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Revenues |
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Oil |
$ | $ | $ | $ | ||||||||||||
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 |
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Loss on derivatives, net |
( |
) | ( |
) | ( |
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Interest expense, net |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
Total other expense, net |
( |
) | ( |
) | ( |
) | ( |
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Net income |
$ | $ | $ | $ | ||||||||||||
Basic and diluted net income per common unit |
$ | $ | $ | $ | ||||||||||||
Weighted average common units outstanding - basic and diluted |
See notes to consolidated financial statements.
Energy 11, L.P.
Consolidated Statements of Partners’ Equity
(Unaudited)
Limited Partner |
Class B |
General Partner |
Total Partners' |
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Common Units |
Amount |
Units |
Amount |
Amount |
Equity |
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Balances - December 31, 2020 |
$ | $ | - | $ | ( |
) | $ | |||||||||||||||||
Net income - three months ended March 31, 2021 |
- | - | - | - | ||||||||||||||||||||
Balances - March 31, 2021 |
- | ( |
) | |||||||||||||||||||||
Net income - three months ended June 30, 2021 |
- | - | - | - | ||||||||||||||||||||
Balances - June 30, 2021 |
$ | $ | - | $ | ( |
) | $ | |||||||||||||||||
Balances - December 31, 2021 |
$ | $ | - | $ | ( |
) | $ | |||||||||||||||||
Distributions declared and paid to common units ($ |
- | ( |
) | - | - | - | ( |
) | ||||||||||||||||
Net income - three months ended March 31, 2022 |
- | - | - | - | ||||||||||||||||||||
Balances - March 31, 2022 |
- | ( |
) | |||||||||||||||||||||
Distributions declared and paid to common units ($ |
- | ( |
) | - | - | - | ( |
) | ||||||||||||||||
Net income - three months ended June 30, 2022 |
- | - | - | - | ||||||||||||||||||||
Balances - June 30, 2022 |
$ | $ | - | $ | ( |
) | $ |
See notes to consolidated financial statements.
Energy 11, L.P.
Consolidated Statements of Cash Flows
(Unaudited)
Six Months Ended |
Six Months Ended |
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June 30, 2022 |
June 30, 2021 |
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Cash flow from operating activities: |
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Net income |
$ | $ | ||||||
Adjustments to reconcile net income to cash from operating activities: |
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Depreciation, depletion, amortization and accretion |
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(Gain) loss on mark-to-market of derivatives, net |
( |
) | ||||||
Non-cash expenses, net |
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Changes in operating assets and liabilities: |
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Accounts receivable |
( |
) | ( |
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Other 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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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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Cash paid for loan costs |
( |
) | ||||||
Proceeds from (payments on) BancFirst revolving credit facility |
( |
) | ||||||
Payments on Simmons revolving credit facility |
( |
) | ||||||
Payments on affiliate term loan |
( |
) | ||||||
Distributions paid to limited partners |
( |
) | ||||||
Net cash flow used in financing activities |
( |
) | ( |
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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 |
$ | $ | ||||||
Interest paid |
$ | $ | ||||||
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 11, L.P.
Notes to Consolidated Financial Statements
June 30, 2022
(Unaudited)
Note 1. Partnership Organization
Energy 11, L.P. (the “Partnership”) is a
As of June 30, 2022, the Partnership owned an approximate
Whiting Petroleum Corporation (“Whiting”) and Oasis Petroleum Inc. (“Oasis”), two of the largest producers in the Williston basin of North Dakota, operated substantially all of the Sanish Field Assets through June 30, 2022. On July 1, 2022, Chord Energy Corporation (“Chord”, NASDAQ: CHRD) announced the successful completion of the combination of Whiting and Oasis. The Partnership anticipates minimal disruption to its normal course business as a result of this transaction, and Chord will continue to administer the ongoing drilling program described below in Note 3. Oil and Natural Gas Investments.
The general partner of the Partnership is Energy 11 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. 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 consolidated financial statements included in its 2021 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2022 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2022.
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 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.
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, 2022. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.
Note 3. Oil and Natural Gas Investments
On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate
Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of
The Partnership estimates the approximate $
Note 4. Debt
Revolving Credit Facilities
In November 2017, the Partnership, as the borrower, entered into a loan agreement (the “Simmons Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto. Through various amendments, the Simmons Loan Agreement provided for a revolving credit facility (“Simmons Credit Facility”) with a commitment amount of $
On May 13, 2021, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“BF Loan Agreement”) with BancFirst, as administrative agent for the lenders (the “Lender”), which provides for a revolving credit facility (“BF Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $
At closing, the Partnership borrowed approximately $
Also, the BF Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production under certain conditions. As amended in March 2022, the BF Loan Agreement no longer requires the Partnership to enter into future hedging transactions as long as the Partnership maintains a utilization rate of less than or equal to 35% of the current borrowing base on the BF Credit Facility. As of June 30, 2022, the Partnership was not subject to any additional hedging requirements as its utilization rate was less than or equal to 35% of the current borrowing base. However, the Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 35% but less than 50% of the current borrowing base, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 50% of the current borrowing base.
See Note 7. Risk Management for more information on the Partnership’s risk management program as required under the BF Loan Agreement.
The BF Credit Facility contains prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants include:
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A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.00 |
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A minimum ratio of current assets to current liabilities of 1.00 to 1.00 |
The BF Loan Agreement does restrict the Partnership’s ability to pay limited partner distributions if the outstanding balance of the BF Credit Facility is greater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base. If the Partnership maintains a credit facility utilization of equal to or less than 50%, the Partnership is permitted to make distributions so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. As of June 30, 2022, the Partnership was not subject to this restriction, as (i) the outstanding balance was less than 50% of the current borrowing base and (ii) the Partnership was in compliance with its debt service coverage ratio.
At June 30, 2022, the outstanding balance on the BF Credit Facility was approximately $
At June 30, 2022 and December 31, 2021, the outstanding balance on the BF Credit Facility was approximately $
Note 5. 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:
2022 |
2021 |
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Balance at January 1 |
$ | $ | ||||||
Well additions |
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Accretion |
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Revisions |
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Balance at June 30 |
$ | $ |
Note 6. Fair Value of Financial Instruments
The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:
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Level 1: Quoted prices in active markets for identical assets |
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Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument |
● |
Level 3: Significant unobservable inputs |
The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the six months ended June 30, 2022 and 2021, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.
As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2022 and December 31, 2021.
Fair Value Measurements at June 30, 2022 |
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Quoted Prices in |
Significant Other Observable Inputs |
Significant Unobservable Inputs |
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Commodity derivatives - current liabilities |
$ | $ | ( |
) | $ | |||||||
Commodity derivatives - non-current liabilities |
( |
) | ||||||||||
Total |
$ | $ | ( |
) | $ |
Fair Value Measurements at December 31, 2021 |
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Quoted Prices in |
Significant Other Observable Inputs |
Significant Unobservable Inputs |
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Commodity derivatives - current liabilities |
$ | $ | ( |
) | $ | |||||||
Commodity derivatives - noncurrent liabilities |
( |
) | ||||||||||
Total |
$ | $ | ( |
) | $ |
The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheet at June 30, 2022 and December 31, 2021. See additional detail in Note 7. Risk Management.
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 liabilities, 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.
Note 7. Risk Management
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. Therefore, the Partnership periodically 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.
In accordance with the amended Simmons Loan Agreement discussed in Note 4.
As of June 30, 2022 and December 31, 2021, the Partnership’s derivative instruments were in a loss position. The Partnership recognized total liabilities of approximately $
The Partnership did not designate its 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 following table presents the settlement losses of matured derivative instruments and non-cash mark-to-market gains (losses) for the periods presented.
Three Months Ended |
Three Months Ended |
Six Months Ended |
Six Months Ended |
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Settlement loss on matured derivatives |
$ | ( |
) | $ | $ | ( |
) | $ | ( |
) | ||||||
Gain (loss) on mark-to-market of derivatives, net |
( |
) | ||||||||||||||
Loss on derivatives, net |
$ | ( |
) | $ | $ | ( |
) | $ | ( |
) |
Settlements on matured derivatives above reflect realized losses 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 or losses above represent the change in fair value of derivative instruments which were held at period-end. Unrealized gains or losses do not represent actual settlements or payments made to or from the counterparty.
The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s future oil and natural gas production.
Settlement Period |
Basis |
Product |
Volume |
Weighted Average |
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07/2022 - 12/2022 |
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01/2023 - 09/2023 |
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08/2022 - 12/2022 |
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01/2023 - 09/2023 |
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The Partnership’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments. The use of derivative instruments involves the risk that the Partnership’s counterparty will be unable to meet the financial terms of such instruments.
Note 8. 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 on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership had completed the sale of approximately
Under the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of
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 with respect to Class B units and will not make the contingent incentive payments to the Dealer Manager, until Payout occurs.
The Partnership Agreement provides that Payout 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 unit, regardless of the amount paid for the 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, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement; |
● | Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%). |
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.
In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to market volatility caused by the onset of the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. Further, the Partnership was restricted in making distributions to limited partners under the Simmons Loan Agreement and BF Loan Agreement (both described above) until certain conditions within those credit agreements had been met. In November 2021, the Partnership successfully met the required conditions under the BF Loan Agreement to resume distributions to limited partners. Subsequently, the General Partner approved a partial distribution in November 2021 and has paid full monthly distributions in December 2021 through June 2022. For the three and six months ended June 30, 2022, the Partnership paid distributions of $
The Partnership accumulates unpaid distributions based on an annualized return of seven percent (
Note 9. Related Parties
The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, David S. McKenney, Chief Financial Officer, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Mr. Knight and Mr. McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. Entities owned by Messrs. Keating and Mallick own non-voting, Class B units in the general partner of ER12.
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.
For the three and six months ended June 30, 2022, 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 ER12, 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 ER12 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, 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 six months ended June 30, 2022, approximately $
Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.
Note 10. Subsequent Events
In July 2022, the Partnership declared and paid $
As of June 30, 2022, the Partnership had approximately $
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:
● |
the impact of and ongoing recovery from COVID-19; |
● |
any impact of the ongoing Russian-Ukrainian conflict on the global energy markets; |
● |
references to future success in the Partnership’s drilling and marketing activities; |
● |
the Partnership’s business strategy; |
● |
estimated future distributions; |
● |
estimated future capital expenditures; |
● |
sales of the Partnership’s properties and other liquidity events; |
● |
competitive strengths and goals; and |
● |
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, 2021 and the following:
● |
that the Partnership’s development of its oil and gas properties may not be successful or that the Partnership’s 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 the Partnership acquired an interest are productive, but do not produce enough revenue to return the investment made; |
● |
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; |
● |
current credit market conditions and the Partnership’s ability to obtain long-term financing or refinancing debt for the Partnership’s drilling activities in a timely manner and on terms that are consistent with what the Partnership projects; |
● |
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 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, 2021.
Overview
The Partnership was formed as a Delaware limited partnership. The general partner is Energy 11 GP, LLC (the “General Partner”). The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership began offering common units of limited partner interest (the “common units”) on a best-efforts basis on January 22, 2015, the date the Partnership’s initial Registration Statement on Form S-1 (File No. 333-197476) was declared effective by the SEC. The Partnership completed its best-efforts offering on April 24, 2017. Total common units sold were approximately 19.0 million for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 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 and develop oil and gas properties located onshore in the United States. On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million.
Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 84 new wells in the Sanish field under a drilling program administered primarily by Whiting Petroleum Corporation (“Whiting”). Fifty-six (56) of these 84 wells have been completed and were producing at June 30, 2022. The Partnership has 27 wells that are in-process as of June 30, 2022 and expects one additional well to commence drilling in the third quarter of 2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 84 wells is approximately $108 million, of which approximately $95 million had been incurred as of June 30, 2022. See additional detail in “Oil and Natural Gas Properties” below.
As a result of its acquisitions and completed drilling during the period of ownership, as of June 30, 2022, the Partnership owned an approximate 25% non-operated working interest in 269 producing wells, an estimated approximate 21% non-operated working interest in 27 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”).
Whiting and Oasis Petroleum Inc. (“Oasis”), two of the largest producers in the Williston basin of North Dakota, operated substantially all of the Sanish Field Assets through June 30, 2022. On July 1, 2022, Chord Energy Corporation (“Chord”, NASDAQ: CHRD) announced the successful completion of the combination of Whiting and Oasis. The Partnership anticipates minimal disruption to its normal course business as a result of this transaction, and Chord will continue to administer the ongoing drilling program described above.
Current Price Environment
Oil, natural gas and natural gas liquids 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 in Russia and 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, beginning in March and April 2020. As government-mandated COVID-19 restrictions eased during the fourth quarter of 2020 and into 2021, demand for oil and natural gas returned. Production restraint by domestic and foreign operators in 2021, in conjunction with higher worldwide demand during the prolonged recovery from COVID-19, contributed to higher commodity prices throughout 2021. The ongoing military conflict between Russia and Ukraine and related economic sanctions imposed on Russia has further exacerbated supply shortages, causing oil prices to increase even more during the first half of 2022.
The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2022 and 2021.
Three Months Ended June 30, |
Percent |
Six Months Ended June 30, |
Percent |
|||||||||||||||||||||
2022 |
2021 |
Change |
2022 |
2021 |
Change | |||||||||||||||||||
Average market closing prices (1) |
||||||||||||||||||||||||
Oil (per Bbl) |
$ | 108.52 | $ | 66.17 | 64.0 | % | $ | 101.77 | $ | 62.22 | 63.6 | % | ||||||||||||
Natural gas (per Mcf) |
$ | 7.50 | $ | 2.95 | 154.2 | % | $ | 6.08 | $ | 3.22 | 88.8 | % |
(1) |
Based on average NYMEX futures closing prices (oil) and NYMEX/Henry Hub spot prices (natural gas) |
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.
Results of Operations
In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly sold 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 summarizes the results from operations, including production, of the Partnership’s non-operated working interest for the three and six months ended June 30, 2022 and 2021.
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||||||||||||||||||||||||||
2022 |
Percent of Revenue |
2021 |
Percent of Revenue |
Percent |
2022 |
Percent of Revenue |
2021 |
Percent of Revenue |
Percent |
|||||||||||||||||||||||||||||||
Total revenues |
$ | 24,433,937 | 100.0 | % | $ | 13,879,473 | 100.0 | % | 76.0 | % | $ | 49,925,860 | 100.0 | % | $ | 27,483,549 | 100.0 | % | 81.7 | % | ||||||||||||||||||||
Production expenses |
3,773,564 | 15.4 | % | 2,867,144 | 20.7 | % | 31.6 | % | 8,435,650 | 16.9 | % | 5,523,221 | 20.1 | % | 52.7 | % | ||||||||||||||||||||||||
Production taxes |
1,841,483 | 7.5 | % | 1,093,447 | 7.9 | % | 68.4 | % | 3,761,440 | 7.5 | % | 2,095,399 | 7.6 | % | 79.5 | % | ||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion |
3,646,669 | 14.9 | % | 4,952,799 | 35.7 | % | -26.4 | % | 9,079,655 | 18.2 | % | 9,840,216 | 35.8 | % | -7.7 | % | ||||||||||||||||||||||||
General and administrative expenses |
492,839 | 2.0 | % | 315,832 | 2.3 | % | 56.0 | % | 1,076,091 | 2.2 | % | 847,130 | 3.1 | % | 27.0 | % | ||||||||||||||||||||||||
Production (BOE): |
||||||||||||||||||||||||||||||||||||||||
Oil |
190,120 | 196,817 | -3.4 | % | 428,086 | 401,495 | 6.6 | % | ||||||||||||||||||||||||||||||||
Natural gas |
49,329 | 46,725 | 5.6 | % | 102,535 | 90,664 | 13.1 | % | ||||||||||||||||||||||||||||||||
Natural gas liquids |
37,989 | 38,792 | -2.1 | % | 80,566 | 75,807 | 6.3 | % | ||||||||||||||||||||||||||||||||
Total |
277,438 | 282,334 | -1.7 | % | 611,187 | 567,966 | 7.6 | % | ||||||||||||||||||||||||||||||||
Average sales price per unit: |
||||||||||||||||||||||||||||||||||||||||
Oil (per Bbl) |
$ | 105.43 | $ | 60.30 | 74.8 | % | $ | 96.81 | $ | 55.97 | 73.0 | % | ||||||||||||||||||||||||||||
Natural gas (per Mcf) |
7.37 | 3.09 | 138.5 | % | 6.58 | 4.31 | 52.7 | % | ||||||||||||||||||||||||||||||||
Natural gas liquids (per Bbl) |
58.12 | 29.54 | 96.8 | % | 55.09 | 35.21 | 56.5 | % | ||||||||||||||||||||||||||||||||
Combined (per BOE) |
88.07 | 49.16 | 79.2 | % | 81.69 | 48.39 | 68.8 | % | ||||||||||||||||||||||||||||||||
Average unit cost per BOE: |
||||||||||||||||||||||||||||||||||||||||
Production expenses |
13.60 | 10.16 | 33.9 | % | 13.80 | 9.72 | 42.0 | % | ||||||||||||||||||||||||||||||||
Production taxes |
6.64 | 3.87 | 71.4 | % | 6.15 | 3.69 | 66.7 | % | ||||||||||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion |
13.14 | 17.54 | -25.1 | % | 14.86 | 17.33 | -14.3 | % | ||||||||||||||||||||||||||||||||
Capital expenditures |
$ | 16,194,361 | $ | 10,999,208 | $ | 25,402,845 | $ | 13,324,172 |
Oil, natural gas and NGL revenues
For the three months ended June 30, 2022, revenues from oil, natural gas and NGL sales were $24.4 million. Revenues for the sale of crude oil were $20.0 million, which resulted in a realized price of $105.43 per barrel. Revenues for the sale of natural gas were $2.2 million, which resulted in a realized price of $7.37 per Mcf. Revenues for the sale of NGLs were $2.2 million, which resulted in a realized price of $58.12 per BOE of sold production. For the three months ended June 30, 2021, revenues for oil, natural gas and NGL sales were $13.9 million. Revenues for the sale of crude oil were $11.9 million, which resulted in a realized price of $60.30 per barrel. Revenues for the sale of natural gas were $0.9 million, which resulted in a realized price of $3.09 per Mcf. Revenues for the sale of NGLs were $1.1 million, which resulted in a realized price of $29.54 per BOE of sold production.
For the six months ended June 30, 2022, revenues from oil, natural gas and NGL sales were $49.9 million. Revenues for the sale of crude oil were $41.4 million, which resulted in a realized price of $96.81 per barrel. Revenues for the sale of natural gas were $4.0 million, which resulted in a realized price of $6.58 per Mcf. Revenues for the sale of NGLs were $4.4 million, which resulted in a realized price of $55.09 per BOE of sold production. For the six months ended June 30, 2021, revenues for oil, natural gas and NGL sales were $27.5 million. Revenues for the sale of crude oil were $22.5 million, which resulted in a realized price of $55.97 per barrel. Revenues for the sale of natural gas were $2.3 million, which resulted in a realized price of $4.31 per Mcf. Revenues for the sale of NGLs were $2.7 million, which resulted in a realized price of $35.21 per BOE of sold production.
The Partnership’s results for the three and six months ended June 30, 2022 were positively impacted by the significant increase in market prices of oil and natural gas when compared to the same periods of 2021. In addition, the Partnership continues to benefit from the easing of market imbalances and supply chain constraints that developed during the spring and summer of 2020 due to COVID-19, realized through reduced differentials (see below). The Partnership’s realized sales prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.
The Partnership has completed 50 new wells since the fourth quarter of 2019, of which 28 were completed and turned to sales during the second quarter of 2021 through the second quarter of 2022. Sold production volumes were flat when comparing the three-month periods ended June 30, 2022 and 2021, as production from newly-completed wells effectively offset natural production declines. In addition to natural production decline, the Williston Basin in North Dakota was hit with a late-season snowstorm that resulted in significant downtime for producing wells during April 2022, which negatively impacted production volumes during the second quarter of 2022. As the wells currently in various stages of the drilling and completion process as of June 30, 2022 are completed, the Partnership anticipates its sold production volumes will increase during the third and fourth quarters of 2022. Sold production for the Sanish Field Assets was approximately 3,000 BOE and 3,400 BOE per day for the three and six months ended June 30, 2022 and 2021, respectively, while sold production for the Sanish Field Assets was approximately 3,100 BOE per day for the three and six months ended June 30, 2021.
If the operators of the Sanish Field Assets are unable to produce, process and sell oil and natural gas at economical prices, these operators may curtail daily production, shut-in producing wells or seek other cost-cutting measures, and could continue so long as producing is uneconomical. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL production. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion of the Partnership’s investment in new wells in “Liquidity and Capital Resources” below.
Oil 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 Sanish field. 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, oil price differentials were approximately 50-60% less during the three and six months ended June 30, 2022 than those of the same periods of 2021, respectively.
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. In February 2022, the United States Supreme Court declined to take a case brought by the Dakota Access Pipeline operators that challenged the requirement of an updated environmental review as upheld by lower courts. The U.S. Army Corps of Engineers report is anticipated to be issued in the fall of 2022. If use of the Dakota Access Pipeline or any other region pipelines is 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 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 contract in effect for the extraction, transportation, treatment and marketing of oil and natural gas.
For the three months ended June 30, 2022 and 2021, production expenses were $3.8 million and $2.9 million, respectively, and production expenses per BOE of sold production were $13.60 and $10.16, respectively. For the six months ended June 30, 2022, production expenses were $8.4 million and $5.5 million, respectively, and production expenses per BOE of sold production were $13.80 and $9.72, respectively. Production expenses per BOE increased in the three and six months ended June 30, 2022, in comparison to the same period of 2021, as a result of (i) an increase in lease operating and workover expenses as certain of the Partnership’s existing wells have required additional maintenance and/or rework to either maintain production efficiency or return to full production, 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 June 30, 2022 and 2021 were $1.8 million (8% of revenue) and $1.1 million (8% of revenue), respectively. Production taxes for the six months ended June 30, 2022 and 2021 were $3.8 million (8% of revenue) and $2.1 million (8% of revenue), respectively.
General and administrative expenses
The principal components of general and administrative expense are accounting, legal and consulting fees. General and administrative expenses for the three months ended June 30, 2022 and 2021 were $0.5 million and $0.3 million, respectively. General and administrative expenses for the six months ended June 30, 2022 and 2021 were $1.1 million and $0.8 million, respectively.
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. DD&A for the three months ended June 30, 2022 and 2021 was $3.6 million and $5.0 million, and DD&A per BOE of sold production was $13.14 and $17.54, respectively. DD&A for the six months ended June 30, 2022 and 2021 was $9.1 million and $9.8 million, and DD&A per BOE of sold production was $14.86 and $17.33, respectively. The decrease in DD&A expense per BOE of production in the first half of 2022 is primarily due to the increase of the Partnership’s estimated proved undeveloped reserves during the most recent reserves analyses (as of December 31, 2021 and June 30, 2022) resulting from changes in the future drill schedule.
Loss on derivatives, net
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.
In accordance with the Partnership’s previous credit facility, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021. In July 2021, the Partnership began its risk management program required under the BancFirst Loan Agreement by entering into costless collar derivative contracts for the period from July 2021 to September 2023.
The Partnership did not designate its 2021 or 2022 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 following table presents settlements of its matured derivative instruments and the non-cash, mark-to-market gains or losses recorded during the periods presented.
Three Months Ended |
Three Months Ended |
Six Months Ended |
Six Months Ended |
|||||||||||||
Settlement loss on matured derivatives |
$ | (2,467,491 | ) | $ | - | $ | (3,713,700 | ) | $ | (1,182,420 | ) | |||||
Gain (loss) on mark-to-market of derivatives, net |
49,971 | - | (7,394,804 | ) | 602,760 | |||||||||||
Loss on derivatives, net |
$ | (2,417,520 | ) | $ | - | $ | (11,108,504 | ) | $ | (579,660 | ) |
The Partnership’s oil production contracts that expired during the three months ended June 30, 2022 represented approximately 85,000 barrels of oil. The Partnership realized a loss of approximately $2.4 million, equating to an approximate loss of $28.33 per barrel, on its hedged oil production, and an approximate loss of $12.67 per barrel of total sold oil production for the second quarter of 2022. The Partnership’s natural gas production contracts that expired during the three months ended June 30, 2022 represented 90,000 MMBtu of produced natural gas. The Partnership realized a loss of approximately $59,000, equating to an approximate loss of $0.66 per MMBtu, on its hedged natural gas production, and an approximate loss $0.20 per MMBtu of total sold natural gas production for the second quarter of 2022.
The Partnership’s oil production contracts that expired during the six months ended June 30, 2022 represented approximately 173,000 barrels of oil. The Partnership realized a loss of approximately $3.7 million, equating to an approximate loss of $21.12 per barrel, on its hedged oil production, and an approximate loss of $8.54 per barrel of total sold oil production for the first half of 2022. The Partnership’s natural gas production contracts that expired during the six months ended June 30, 2022 represented 200,000 MMBtu of produced natural gas. The Partnership realized a loss of approximately $59,000, equating to an approximate loss of $0.30 per MMBtu, on its hedged natural gas production, and an approximate loss $0.10 per MMBtu of total sold natural gas production for the first half of 2022.
The Partnership’s oil production contracts that expired during the six months ended June 30, 2021 represented approximately 105,000 barrels of oil. The Partnership’s realized loss of approximately $1.2 million equated to an approximate loss of $11.26 per barrel of hedged oil production, and an approximate loss of $2.95 per barrel of total sold oil production for the first half of 2021. The Partnership’s natural gas production contracts that expired during the six months ended June 30, 2021 represented 120,000 MMBtu of natural gas; however, these natural gas production contracts were settled at no cost or benefit to the Partnership, as the contract price on the date of settlement was within the established floor and ceiling prices.
The mark-to-market (non-cash, unrealized) gains or losses recorded for the three and six months ended June 30, 2022 and 2021 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.
The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s future oil and natural gas production.
Settlement Period |
Basis |
Product |
Volume |
Weighted Average |
||||
07/2022 - 12/2022 |
NYMEX |
Oil (bbls) |
159,000 |
50.00 / 72.00 |
||||
01/2023 - 09/2023 |
NYMEX |
Oil (bbls) |
224,000 |
50.00 / 69.72 |
||||
08/2022 - 12/2022 |
Henry Hub |
Gas (MMbtu) |
150,000 |
2.00 / 4.50 |
||||
01/2023 - 09/2023 |
Henry Hub |
Gas (MMbtu) |
273,000 |
2.00 / 4.43 |
Interest expense, net
Interest expense, net, for the three months ended June 30, 2022 and 2021 was $0.2 million and $0.5 million, respectively. Interest expense, net, for the six months ended June 30, 2022 and 2021 was $0.5 million and $1.0 million, respectively. The primary component of Interest expense, net, during the three- and six-month periods ended June 30, 2022 was interest expense on the BancFirst Credit Facility. The primary component of Interest expense, net, during the three- and six-month periods ended June 30, 2021 was interest expense on the BancFirst Credit Facility, the Simmons Credit Facility (paid in full in May 2021) and a related-party term loan (paid in full in March 2021).
Supplemental Non-GAAP Measure
The Partnership uses “Adjusted EBITDAX”, defined as earnings before (i) interest 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 alternatives 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 terms exactly as the Partnership defines such terms, 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 six months ended June 30, 2022 and 2021.
Three Months Ended |
Three Months Ended |
Six Months Ended |
Six Months Ended |
|||||||||||||
Net income |
$ | 12,015,515 | $ | 4,126,910 | $ | 15,960,310 | $ | 7,590,379 | ||||||||
Interest expense, net |
246,347 | 523,341 | 504,210 | 1,007,544 | ||||||||||||
Depreciation, depletion, amortization and accretion |
3,646,669 | 4,952,799 | 9,079,655 | 9,840,216 | ||||||||||||
Exploration expenses |
- | - | - | - | ||||||||||||
Non-cash (gain) loss on mark-to-market of derivatives, net |
(49,971 | ) | - | 7,394,804 | (602,760 | ) | ||||||||||
Adjusted EBITDAX |
$ | 15,858,560 | $ | 9,603,050 | $ | 32,938,979 | $ | 17,835,379 |
Liquidity and Capital Resources
Historically, the Partnership’s principal sources of liquidity have been cash on hand, the cash flow generated from the Sanish Field Assets, and availability under the Partnership’s revolving credit facility, if any. The Partnership generated approximately $43.5 million in cash flow from operating activities for the year ended December 31, 2021 and approximately $34.2 million in cash flow from operating activities for the six months ended June 30, 2022. In May 2021, the Partnership successfully refinanced its existing Simmons Bank credit facility and used the initial closing proceeds of approximately $40 million from the refinancing with BancFirst to fully repay the outstanding balance on the Simmons credit facility. From May 2021 through June 2022, the Partnership made principal payments on the BancFirst credit facility of approximately $24 million using excess cash flow from operations. As of June 30, 2022, the Partnership had approximately $20 million in accrued capital expenditures to its operators related to the drilling program discussed below in “Oil and Natural Gas Properties.” In addition to using cash flow from operations, the Partnership has borrowed approximately $7 million on the BancFirst credit facility during the third quarter of 2022 to pay its capital obligations as they become due under the drilling program.
The Partnership anticipates its cash on-hand, cash flow from operations and availability under its BancFirst credit facility will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below. In addition, the Partnership met all conditions under the BancFirst Credit Facility to resume distributions in November 2021. The Partnership’s ability to make future distributions to its limited partners is contingent on remaining compliant with all applicable covenants under its BancFirst credit facility as well as ensuring the outstanding balance of the credit facility is at or below 50% of the Partnership’s current borrowing base. The Partnership can offer no assurance to the payment of distributions in future months; however, the General Partner will monitor payment of future monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations, payments on the BancFirst credit facility and capital expenditures for new wells.
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’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 participate in future drilling programs as proposed by the operators of the Sanish Field Assets and/or to fund any future distributions to its limited partners. 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.
Financing
See further discussion of the Partnership’s BancFirst credit facility in “Note 4. Debt” in Part I, Item 1 of this Form 10-Q.
Partners’ Equity
The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership sold approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.
Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold in the offering, the total contingent fee is a maximum of approximately $15.0 million, which will only be paid if Payout occurs, as defined in “Note 8. Capital Contribution and Partners’ Equity” in Part I, Item 1 of this Form 10-Q.
Distributions
In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to market volatility caused by the onset of the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. Further, the Partnership was restricted in making distributions to limited partners under the Simmons Loan Agreement and BF Loan Agreement (both described above) until certain conditions within those credit agreements had been met. In November 2021, the Partnership successfully met the required conditions under the BF Loan Agreement to resume distributions to limited partners. Subsequently, the General Partner approved a partial distribution in November 2021 and has paid full monthly distributions in December 2021 through June 2022. For the three and six months ended June 30, 2022, the Partnership paid distributions of $0.349041 and $0.671232, or $6.6 million and $12.7 million, respectively.
The Partnership accumulates unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs. As of June 30, 2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.
Oil and Natural Gas Properties
The Partnership incurred approximately $26.5 million and $13.3 million in capital expenditures for the six months ended June 30, 2022 and 2021, respectively.
Since the beginning of 2019, the Partnership has elected to participate in the drilling and completion of 78 new wells in the Sanish field. Fifty (50) of these 78 wells have been completed and were producing at June 30, 2022; the Partnership has an approximate non-operated working interest of 20% in these 50 wells. The Partnership has an estimated approximate non-operated working interest of 21% in 27 wells that are in-process as of June 30, 2022. The Partnership has an estimated approximate non-operated working interest of 19% in one additional well that had not commenced drilling as of June 30, 2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 78 wells is approximately $100 million, of which approximately $87 million was incurred as of June 30, 2022.
The Partnership anticipates its operators will complete the remaining 28 wells during the next three to nine months; however, completion of the wells is not in the Partnership’s control. The Partnership estimates the approximate $10 to $20 million in capital expenditures to fully pay for its recently-completed wells along with the remaining 28 wells in various stages of the drilling and completion process will be incurred during the remainder of 2022 based on the best available information regarding current capital investment plans from its operators. Many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures for the remainder of 2022 and estimated capital expenditures could be significantly different from amounts actually invested. Because the Partnership’s operator is committed to drilling in the Sanish Field, the Partnership may be obligated to invest up to an additional $100 million in capital expenditures from 2023 through 2027 to participate in new well development in the Sanish Field without becoming subject to non-consent penalties under the joint operating agreements governing the Sanish Field Assets.
As described above, the Partnership’s liquidity is currently dependent upon cash on-hand, cash from operations and availability under the BancFirst Credit Facility. If the Partnership is not able to generate sufficient cash from operations or there is no availability under its credit facility to fund capital expenditures, it may not be able to complete its capital obligations presented by its operators or participate fully in future 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 until a penalty is received by the parties that drilled the well.
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, including approving the new Affiliate Loan.
See further discussion in “Note 9. Related Parties” in Part I, Item 1 of this Form 10-Q.
Subsequent Events
In July 2022, the Partnership declared and paid $2.5 million, or $0.134247 per outstanding common unit, in distributions to its holders of common units.
As of June 30, 2022, the Partnership had approximately $20 million in accrued capital expenditures to its operators related to the drilling program. In addition to using cash flow from operations, the Partnership borrowed approximately $7 million on the BF Credit Facility in July and August to pay its capital obligations under the drilling program as they have become due.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership’s BancFirst Credit Facility is subject to a variable interest rate; information regarding this credit facility is contained in Item 1 – Financial Statements (Unaudited) and Notes to Consolidated Financial Statements: Note 4. Debt 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.
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 7. 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 June 30, 2022 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 June 30, 2022 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 2021 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2021 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.
Exhibit No. |
Description |
|
31.1 |
Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002* |
|
31.2 |
Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002* |
|
32.1 |
||
32.2 |
||
101 |
The following materials from Energy 11, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2022 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 these consolidated financial statements, tagged as blocks of text and in detail* |
|
104 |
The cover page from the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2022, 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.
Energy 11, L.P. |
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By: Energy 11 G.P., LLC, its General Partner |
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By: |
/s/ Glade M. Knight |
||
Glade M. Knight |
|||
Chief Executive Officer (Principal Executive Officer) |
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By: |
/s/ David S. McKenney |
||
David S. McKenney |
|||
Chief Financial Officer (Principal Financial and Accounting Officer) |
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Date: August 12, 2022 |