UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☑ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the quarterly period ended September 30, 2019 |
☐ | 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 000-55615
Energy 11, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 46-3070515 |
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) |
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120 W 3rd Street, Suite 220 Fort Worth, Texas | 76102 |
(Address of principal executive offices) | (Zip Code) |
(817) 882-9192
(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 |
None |
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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. Yes ☑ No ☐
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). Yes ☑ No ☐
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 ☐ |
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| Accelerated filer ☐ |
Non-accelerated filer ☐ |
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| Smaller reporting company ☑ |
Emerging growth company ☑ |
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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 ☐ No ☑
As of October 31, 2019, the Partnership had 18,973,474 common units outstanding.
Energy 11, L.P.
Form 10-Q
Index
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PART I. FINANCIAL INFORMATION |
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| Item 1. |
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| Consolidated Balance Sheets – September 30, 2019 and December 31, 2018 | 3 |
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| Consolidated Statements of Operations – Three and nine months ended September 30, 2019 and 2018 | 4 |
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| Consolidated Statements of Cash Flows – Nine months ended September 30, 2019 and 2018 | 6 |
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| Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 14 |
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| Item 3. | 22 | |
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| Item 4. | 22 | |
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PART II. OTHER INFORMATION |
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| Item 1. | 23 | |
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| Item 1A. | 23 | |
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| Item 2. | 23 | |
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| Item 3. | 23 | |
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| Item 4. | 23 | |
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| Item 5. | 23 | |
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| Item 6. | 23 | |
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24 |
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Energy 11, L.P.
Consolidated Balance Sheets
September 30, | December 31, | |||||||
2019 | 2018 | |||||||
(unaudited) | ||||||||
Assets | ||||||||
Cash and cash equivalents | $ | 85,134 | $ | 3,685,327 | ||||
Oil, natural gas and natural gas liquids revenue receivable | 3,856,520 | 6,269,243 | ||||||
Derivative asset | 498,790 | - | ||||||
Other current assets | 207,611 | 198,770 | ||||||
Total Current Assets | 4,648,055 | 10,153,340 | ||||||
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $50,157,260 and $40,806,378, respectively | 311,647,373 | 313,116,985 | ||||||
Total Assets | $ | 316,295,428 | $ | 323,270,325 | ||||
Liabilities | ||||||||
Revolving credit facility | $ | 16,800,000 | $ | 13,800,000 | ||||
Accounts payable and accrued expenses | 6,104,661 | 2,430,656 | ||||||
Total Current Liabilities | 22,904,661 | 16,230,656 | ||||||
Asset retirement obligations | 1,419,645 | 1,294,067 | ||||||
Total Liabilities | 24,324,306 | 17,524,723 | ||||||
Partners’ Equity | ||||||||
Limited partners' interest (18,973,474 common units issued and outstanding) | 291,972,849 | 305,747,329 | ||||||
General partner's interest | (1,727 | ) | (1,727 | ) | ||||
Class B Units (62,500 units issued and outstanding) | - | - | ||||||
Total Partners’ Equity | 291,971,122 | 305,745,602 | ||||||
Total Liabilities and Partners’ Equity | $ | 316,295,428 | $ | 323,270,325 |
See notes to consolidated financial statements.
Energy 11, L.P.
Consolidated Statements of Operations
(Unaudited)
Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||
September 30, 2019 | September 30, 2018 | September 30, 2019 | September 30, 2018 | |||||||||||||
Revenues | ||||||||||||||||
Oil | $ | 6,649,652 | $ | 13,600,381 | $ | 22,612,030 | $ | 36,403,912 | ||||||||
Natural gas | 429,347 | 748,818 | 2,066,813 | 2,233,675 | ||||||||||||
Natural gas liquids | 260,110 | 1,339,689 | 2,069,270 | 3,542,357 | ||||||||||||
Total revenue | 7,339,109 | 15,688,888 | 26,748,113 | 42,179,944 | ||||||||||||
Operating costs and expenses | ||||||||||||||||
Production expenses | 2,228,933 | 2,914,785 | 7,977,046 | 8,536,265 | ||||||||||||
Production taxes | 558,288 | 1,365,925 | 2,132,056 | 3,657,937 | ||||||||||||
General and administrative expenses | 281,308 | 343,955 | 1,043,293 | 1,042,228 | ||||||||||||
Depreciation, depletion, amortization and accretion | 2,767,479 | 4,481,712 | 9,403,364 | 12,705,908 | ||||||||||||
Total operating costs and expenses | 5,836,008 | 9,106,377 | 20,555,759 | 25,942,338 | ||||||||||||
Operating income | 1,503,101 | 6,582,511 | 6,192,354 | 16,237,606 | ||||||||||||
Gain (loss) on derivatives | 498,790 | (38,921 | ) | 498,790 | (2,943,000 | ) | ||||||||||
Interest expense, net | (207,847 | ) | (183,480 | ) | (598,063 | ) | (574,127 | ) | ||||||||
Total other expense, net | 290,943 | (222,401 | ) | (99,273 | ) | (3,517,127 | ) | |||||||||
Net income | $ | 1,794,044 | $ | 6,360,110 | $ | 6,093,081 | $ | 12,720,479 | ||||||||
Basic and diluted net income per common unit | $ | 0.09 | $ | 0.34 | $ | 0.32 | $ | 0.67 | ||||||||
Weighted average common units outstanding - basic and diluted | 18,973,474 | 18,973,474 | 18,973,474 | 18,973,474 |
See notes to consolidated financial statements.
Energy 11, L.P.
Consolidated Statements of Partners’ Equity
(Unaudited)
Limited Partner | Class B | General Partner | Total Partners' | |||||||||||||||||||||
Common Units | Amount | Units | Amount | Amount | Equity | |||||||||||||||||||
Balances - December 31, 2017 | 18,973,474 | $ | 314,254,337 | 62,500 | $ | - | $ | (1,727 | ) | $ | 314,252,610 | |||||||||||||
Distributions declared and paid to common units ($0.299178 per common unit) | - | (5,676,446 | ) | - | - | - | (5,676,446 | ) | ||||||||||||||||
Net income - three months ended March 31, 2018 | - | 3,325,445 | - | - | - | 3,325,445 | ||||||||||||||||||
Balances - March 31, 2018 | 18,973,474 | 311,903,336 | 62,500 | - | (1,727 | ) | 311,901,609 | |||||||||||||||||
Distributions declared and paid to common units ($0.369041 per common unit) | - | (7,001,990 | ) | - | - | - | (7,001,990 | ) | ||||||||||||||||
Net income - three months ended June 30, 2018 | - | 3,034,924 | - | - | - | 3,034,924 | ||||||||||||||||||
Balances - June 30, 2018 | 18,973,474 | 307,936,270 | 62,500 | - | (1,727 | ) | 307,934,543 | |||||||||||||||||
Distributions declared and paid to common units ($0.413424 per common unit) | - | (7,844,089 | ) | - | - | - | (7,844,089 | ) | ||||||||||||||||
Net income - three months ended September 30, 2018 | - | 6,360,110 | - | - | - | 6,360,110 | ||||||||||||||||||
Balances - September 30, 2018 | 18,973,474 | $ | 306,452,291 | 62,500 | $ | - | $ | (1,727 | ) | $ | 306,450,564 | |||||||||||||
Balances - December 31, 2018 | 18,973,474 | $ | 305,747,329 | 62,500 | $ | - | $ | (1,727 | ) | $ | 305,745,602 | |||||||||||||
Distributions declared and paid to common units ($0.349041 per common unit) | - | (6,622,520 | ) | - | - | - | (6,622,520 | ) | ||||||||||||||||
Net income - three months ended March 31, 2019 | - | 2,339,974 | - | - | - | 2,339,974 | ||||||||||||||||||
Balances - March 31, 2019 | 18,973,474 | 301,464,783 | 62,500 | - | (1,727 | ) | 301,463,056 | |||||||||||||||||
Distributions declared and paid to common units ($0.349041 per common unit) | - | (6,622,521 | ) | - | - | - | (6,622,521 | ) | ||||||||||||||||
Net income - three months ended June 30, 2019 | - | 1,959,063 | - | - | - | 1,959,063 | ||||||||||||||||||
Balances - June 30, 2019 | 18,973,474 | 296,801,325 | 62,500 | - | (1,727 | ) | 296,799,598 | |||||||||||||||||
Distributions declared and paid to common units ($0.349041 per common unit) | - | (6,622,520 | ) | - | - | - | (6,622,520 | ) | ||||||||||||||||
Net income - three months ended September 30, 2019 | - | 1,794,044 | - | - | - | 1,794,044 | ||||||||||||||||||
Balances - September 30, 2019 | 18,973,474 | $ | 291,972,849 | 62,500 | $ | - | $ | (1,727 | ) | $ | 291,971,122 |
See notes to consolidated financial statements.
Energy 11, L.P.
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended | Nine Months Ended | |||||||
September 30, 2019 | September 30, 2018 | |||||||
Cash flow from operating activities: | ||||||||
Net income | $ | 6,093,081 | $ | 12,720,479 | ||||
Adjustments to reconcile net income to cash from operating activities: | ||||||||
Depreciation, depletion, amortization and accretion | 9,403,364 | 12,705,908 | ||||||
(Gain) loss on mark-to-market of derivatives | (498,790 | ) | 410,768 | |||||
Non-cash expenses, net | 37,328 | 33,749 | ||||||
Changes in operating assets and liabilities: | ||||||||
Oil, natural gas and natural gas liquids revenue receivable | 2,412,723 | (2,638,182 | ) | |||||
Other current assets | (36,170 | ) | (108,618 | ) | ||||
Accounts payable and accrued expenses | (603,796 | ) | 837,721 | |||||
Net cash flow provided by operating activities | 16,807,740 | 23,961,825 | ||||||
Cash flow from investing activities: | ||||||||
Additions to oil and natural gas properties | (3,540,372 | ) | (7,260,576 | ) | ||||
Net cash flow used in investing activities | (3,540,372 | ) | (7,260,576 | ) | ||||
Cash flow from financing activities: | ||||||||
Cash paid for loan costs | - | (1,845 | ) | |||||
Proceeds from revolving credit facility | 3,000,000 | - | ||||||
Payments on revolving credit facility | - | (6,200,000 | ) | |||||
Distributions paid to limited partners | (19,867,561 | ) | (20,522,525 | ) | ||||
Net cash flow used in financing activities | (16,867,561 | ) | (26,724,370 | ) | ||||
Decrease in cash and cash equivalents | (3,600,193 | ) | (10,023,121 | ) | ||||
Cash and cash equivalents, beginning of period | 3,685,327 | 11,090,846 | ||||||
Cash and cash equivalents, end of period | $ | 85,134 | $ | 1,067,725 | ||||
Interest paid | $ | 574,334 | $ | 564,701 |
See notes to consolidated financial statements.
Energy 11, L.P.
Notes to Consolidated Financial Statements
September 30, 2019
(Unaudited)
Note 1. Partnership Organization
Energy 11, L.P. (the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership completed its best-efforts offering on April 24, 2017 with a total of approximately 19.0 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.
As of September 30, 2019, the Partnership owned an approximate 25-26% non-operated working interest in 222 currently producing wells, 12 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”), which is part of the Bakken shale formation in the Greater Williston Basin. Whiting Petroleum Corporation (“Whiting”) and Oasis Petroleum North America, LLC (“Oasis”), two of the largest producers in the basin, operate substantially all of the Sanish Field Assets.
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 2018 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2019.
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.
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 nine months ended September 30, 2019 and 2018. 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 5) will occur.
Recently Adopted Accounting Standards
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2016-02, Leases (Topic 842), which amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets as right-of-use assets and lease liabilities. The Partnership concluded there is no material impact to the Partnership’s consolidated financial statements and related disclosures. The Partnership adopted this standard as of January 1, 2019.
Note 3. Oil and Natural Gas Investments
On December 18, 2015, the Partnership completed its first purchase (“Acquisition No. 1”) 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 (“Acquisition No. 2”) 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 (“Acquisition No. 3”) 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.
During 2018, 6 wells were completed by the Partnership’s operators. NaN wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these 2 wells. The other 4 wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.
The Partnership has elected to participate in the drilling and completion of 19 new wells during the nine months ended September 30, 2019. In total, capital expenditures for the drilling and completion of the 19 wells are estimated to be approximately $31 million, and the Partnership will have an average approximate non-operated working interest of 22% in these 19 wells upon completion.
NaN well has been completed and drilling activities have commenced for 12 of the remaining 18 wells. The Partnership has incurred approximately $7.1 million in capital expenditures for these 13 wells as of September 30, 2019. The remaining 18 wells are expected to be completed over the next one to six months from September 30, 2019. As of September 30, 2019 and December 31, 2018, the Partnership had approximately $4.4 million and $0.1 million, respectively, in outstanding capital expenditures, which are included in Accounts payable and accrued liabilities on the Partnership’s consolidated balance sheets.
Note 4. Debt
On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”), which provided for a revolving credit facility with an approved initial commitment amount of $20 million, subject to borrowing base restrictions. The maturity date was November 21, 2019.
Effective September 30, 2019, the Partnership entered into an amendment and restatement of the Loan Agreement (the “Amended Loan Agreement”), which provides for a revolving credit facility (“Credit Facility”) with an approved initial commitment of $40 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The terms of the Amended Loan Agreement are generally similar to those of the original Loan Agreement and include the following: (i) a maturity date of September 30, 2022; (ii) subject to certain exceptions, an interest rate, which did not change from the existing revolving credit facility, equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.50% to 3.50%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Amended Loan Agreement; (iii) an increase to the borrowing base from $30 million to an initially stipulated $40 million; and (iv) an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties. The Revolver Commitment Amount may be increased up to $75 million with lender approval.
At September 30, 2019, the outstanding balance on the Credit Facility was $16.8 million, and the interest rate for the Credit Facility was approximately 4.87%. Outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Revolver Commitment Amount at any time; the effective borrowing base and the Revolver Commitment Amount were both $40 million at September 30, 2019.
At closing, the Partnership paid an origination fee of 0.45% on the increase in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000, and is subject to origination fees of 0.45% for any borrowings made in excess of the Revolver Commitment Amount (as noted above, an increase to the Revolver Commitment Amount would require lender approval). The Partnership is also required to pay an unused facility fee of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter.
The Amended Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer,. If this condition is met, the risk management program must cover at least 50% of the Partnership’s projected total production of oil and natural gas for a rolling 18-month period. At September 30, 2019, the Partnership’s borrowing base of $40 million does not exceed 50% of its estimated producing reserves; therefore, the Partnership is not required to maintain a risk management program. The Amended Loan Agreement does permit the Partnership to enter into derivative contracts with a counterparty at its own discretion so long as the term does not exceed 36 months and does not cover more than 80% of the Partnership’s projected oil and gas volumes.
The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include:
- | A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00 |
- | A minimum ratio of current assets to current liabilities of 1.00 to 1.00 |
- | A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period |
- | A limit to Partnership distributions if certain terms and conditions are not met, including being limited to 50% of the previous quarter EBITDAX beginning April 1, 2020. |
The Partnership was in compliance with the applicable covenants at September 30, 2019.
Subject to availability, the Credit Facility may provide additional liquidity for future capital investments, including the drilling and completion of wells currently being developed and proposed wells by the Partnership’s operators, and other corporate working capital requirements. Under the Credit Facility, the Partnership may make voluntary prepayments in whole or in part at any time without penalty.
As of September 30, 2019 and December 31, 2018, the outstanding balance on the Credit Facility was $16.8 million and $13.8 million, respectively, which approximates its fair market value. The Partnership estimated the fair value of its Credit Facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.
Note 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:
2019 | 2018 | |||||||
Balance at January 1 | $ | 1,294,067 | $ | 1,226,879 | ||||
Well additions | 73,096 | - | ||||||
Accretion | 52,482 | 50,391 | ||||||
Revisions | - | - | ||||||
Balance at September 30 | $ | 1,419,645 | $ | 1,277,270 |
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:
● | Level 1: Quoted prices in active markets for identical assets |
● | 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 three and nine months ended September 30, 2019 and 2018, 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 September 30, 2019. The Partnership had no outstanding derivative contracts as of December 31, 2018.
Fair Value Measurements at September 30, 2019 | ||||||||||||
Quoted Prices in | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||
Commodity derivatives - current assets | $ | - | $ | 498,790 | $ | - | ||||||
Total | $ | - | $ | 498,790 | $ | - |
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 in Derivative asset at September 30, 2019. See additional detail in Note 7. Risk Management.
Fair Value of Other Financial Instruments
The carrying value of the Partnership’s 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. In addition, see Note 4. Debt for the fair value discussion on the Partnership’s debt.
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. In September 2019, the Partnership entered into 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. All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value. As discussed in Note 4. Debt, the Partnership will be required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer.
At September 30, 2019, the Partnership’s costless collar derivative instrument was in a gain position; therefore, a current asset of approximately $0.5 million, which approximates fair value, was recognized as a Derivative asset on the Partnership’s consolidated balance sheet. The fair value of the Derivative asset at September 30, 2019 was determined based on Level 2 inputs as defined under the fair value hierarchy, which include future prices, volatility and time to maturity, among other things. Counterparty statements were utilized to determine the value of the commodity derivative instruments, and the Partnership reviewed and corroborated the counterparty statements using various methodologies and significant observable inputs.
The Partnership has not designated 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 recognized a mark-to-market gain of approximately $0.5 million for the three and nine months ended September 30, 2019, which was recorded on the consolidated statements of operations as Gain (loss) on derivatives. No derivative contracts were settled during the three and nine months ended September 30, 2019.
The Partnership determines the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performs an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional discussion above in Note 6. Fair Value of Financial Instruments.
The following table presents settlements on matured derivative instruments and non-cash gains or losses on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. Non-cash gains or losses below represent the change in fair value of derivative instruments which were held at period-end.
Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||
Settlements on matured derivatives | $ | - | $ | (1,100,682 | ) | $ | - | $ | (2,532,232 | ) | ||||||
Gain (loss) on mark-to-market of derivatives | 498,790 | 1,061,761 | 498,790 | (410,768 | ) | |||||||||||
Gain (loss) on derivatives | $ | 498,790 | $ | (38,921 | ) | $ | 498,790 | $ | (2,943,000 | ) |
At September 30, 2019, the Partnership had 1 derivative contract, which was a costless collar, and was used to establish floor and ceiling prices on future anticipated oil production. The Partnership did not pay or receive a premium related to the costless collar agreement. The contract is settled monthly and there were no settlement payables or receivables at September 30, 2019. The following table reflects information on the open costless collar contract as of September 30, 2019.
Settlement Period | Basis | Oil (Barrels) | Floor / Ceiling Prices | Fair Value of Asset / (Liability) at | ||||||||||
10/01/19 - 03/31/20 | NYMEX (WTI) | 167,000 | $ | 55.00 / 59.25 | $ | 498,790 |
The Partnership’s outstanding derivative instrument is covered by an International Swap Dealers Association Master Agreement (“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 the counterparty that provide for offsetting payables against receivables from separate derivative instruments.
Note 8. Capital Contribution and Partners’ Equity
At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, and the General Partner received Incentive Distribution Rights (defined below).
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 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offerings costs of $349.6 million.
Under the agreement with David Lerner Associates, Inc. (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 through the best-efforts offering, the total contingent fee is a maximum of approximately $15.0 million.
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%). |
For the three and nine months ended September 30, 2019, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $6.6 million and $19.9 million, respectively. For the three and nine months ended September 30, 2018, the Partnership paid distributions of $0.413424 and $1.081643 per common unit, or $7.8 million and $20.5 million, respectively.
Note 9. Related Parties
The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions.
For the three and nine months ended September 30, 2019, approximately $88,000 and $236,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At September 30, 2019, approximately $88,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. For the three and nine months ended September 30, 2018, approximately $58,000 and $188,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.
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. On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that gives ER12 access to the Partnership’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The shared day-to-day costs are split evenly between the two partnerships and any direct third-party costs are paid by the party receiving the services. The shared costs are based on actual costs incurred with no mark-up or profit to the Partnership. The agreement may be terminated at any time by either party upon 60 days written notice.
The Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate of the General Partner. For the three and nine months ended September 30, 2019 and 2018, the Partnership paid $25,611 and $76,833 in each period, respectively, to the affiliate of the General Partner. The office space is shared between the Partnership and ER12; therefore, under the cost sharing agreement, the monthly payment of $8,537 is split between the two partnerships. In addition to the office space, the cost sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner noted above. The compensation due to Clifford J. Merritt, President of the General Partner, is also a shared cost between the Partnership and ER12. For the three and nine months ended September 30, 2019, approximately $65,000 and $200,000, respectively, of expenses subject to the cost sharing agreement were paid by the Partnership and have been or will be reimbursed by ER12. At September 30, 2019, the approximately $65,000 due to the Partnership from ER12 is included in Other current assets in the consolidated balance sheets. For the three and nine months ended September 30, 2018, approximately $64,000 and $175,000 of expenses subject to the cost sharing agreement were incurred by the Partnership and have been reimbursed by ER12.
Note 10. Subsequent Events
In October 2019, the Partnership entered into an amendment and restatement of its existing revolving credit facility, effective September 30, 2019. At closing, the Partnership borrowed an incremental $0.2 million under the restated Credit Facility to pay closing costs. See further discussion above in Note 4. Debt.
In October 2019, the Partnership declared and paid $2.0 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.
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:
● | 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, 2018 and the following:
● | that the Partnership’s strategy of acquiring oil and gas properties on attractive terms and developing those properties may not be successful or that the Partnership’s operations on properties acquired may not be successful; |
● | general economic, market, or business conditions; |
● | changes in laws or regulations; |
● | the risk that the wells in which the Partnership acquires 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, 2018.
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.
As of September 30, 2019, the Partnership owned an approximate 25-26% non-operated working interest in 222 currently producing wells, 12 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”). Substantially all of the Sanish Field Assets are operated by Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL) and Oasis Petroleum North America, LLC (“Oasis”) (NYSE: OAS), two publicly traded oil and gas companies and two of the largest producers in the basin.
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 (“Acquisition No. 1”) 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 (“Acquisition No. 2”) 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 (“Acquisition No. 3”) 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.
During 2018, six wells were completed by the Partnership’s operators. Two wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these two wells. The other four wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.
During the nine months ended September 30, 2019, the Partnership elected to participate in the drilling and completion of 19 new wells. In total, capital expenditures for the drilling and completion of the 19 wells discussed above are estimated to be approximately $31 million, and the Partnership will have an average approximate non-operated working interest of 22% in these 19 wells upon completion.
As of September 30, 2019, one well has been completed and drilling activities have commenced for 12 of the remaining 18 wells. The Partnership has incurred approximately $7.1 million in capital expenditures for these 13 wells as of September 30, 2019. The remaining 18 wells are expected to be completed over the next one to six months from September 30, 2019.
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. Factors contributing to world-wide commodity pricing volatility 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; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. 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, 2019 and 2018.
Three Months Ended September 30, | Percent | Nine Months Ended September 30, | Percent | |||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | |||||||||||||||||||
Average market closing prices (1) | ||||||||||||||||||||||||
Oil (per Bbl) | $ | 56.44 | $ | 69.57 | -18.9 | % | $ | 57.01 | $ | 66.85 | -14.7 | % | ||||||||||||
Natural gas (per Mcf) | $ | 2.38 | $ | 2.93 | -18.8 | % | $ | 2.62 | $ | 2.94 | -10.9 | % |
(1) | Based on average NYMEX futures closing prices (oil) and NYMEX/Henry Hub spot prices (natural gas) |
The Partnership’s revenues are highly sensitive to changes in oil and natural gas prices and to levels of production. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. Dependent on available cash flow, the Partnership intends to seek opportunities to invest in its existing producing wells, drill new wells on existing leasehold sites like the six wells discussed above drilled in 2018 and the 12 wells currently in progress at September 30, 2019 discussed above.
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, (3) production costs per BOE and (4) capital expenditures.
The following is a summary of the results from operations, including production, of the Partnership’s non-operated working interest for the three and nine months ended September 30, 2019 and 2018.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||||||
2019 | Percent of Revenue | 2018 | Percent of Revenue | Percent | 2019 | Percent of Revenue | 2018 | Percent of Revenue | Percent | |||||||||||||||||||||||||||||||
Total revenues | $ | 7,339,109 | 100.0 | % | $ | 15,688,888 | 100.0 | % | -53.2 | % | $ | 26,748,113 | 100.0 | % | $ | 42,179,944 | 100.0 | % | -36.6 | % | ||||||||||||||||||||
Production expenses | 2,228,933 | 30.4 | % | 2,914,785 | 18.6 | % | -23.5 | % | 7,977,046 | 29.8 | % | 8,536,265 | 20.2 | % | -6.6 | % | ||||||||||||||||||||||||
Production taxes | 558,288 | 7.6 | % | 1,365,925 | 8.7 | % | -59.1 | % | 2,132,056 | 8.0 | % | 3,657,937 | 8.7 | % | -41.7 | % | ||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion | 2,767,479 | 37.7 | % | 4,481,712 | 28.6 | % | -38.2 | % | 9,403,364 | 35.2 | % | 12,705,908 | 30.1 | % | -26.0 | % | ||||||||||||||||||||||||
General, administration and other expense | 281,308 | 3.8 | % | 343,955 | 2.2 | % | -18.2 | % | 1,043,293 | 3.9 | % | 1,042,228 | 2.5 | % | 0.1 | % | ||||||||||||||||||||||||
Sold production (BOE): | ||||||||||||||||||||||||||||||||||||||||
Oil | 134,533 | 218,368 | -38.4 | % | 457,259 | 612,220 | -25.3 | % | ||||||||||||||||||||||||||||||||
Natural gas | 34,343 | 39,889 | -13.9 | % | 116,857 | 109,669 | 6.6 | % | ||||||||||||||||||||||||||||||||
Natural gas liquids | 24,807 | 40,293 | -38.4 | % | 99,726 | 109,383 | -8.8 | % | ||||||||||||||||||||||||||||||||
Total | 193,683 | 298,550 | -35.1 | % | 673,842 | 831,272 | -18.9 | % | ||||||||||||||||||||||||||||||||
Average sales price per unit: | ||||||||||||||||||||||||||||||||||||||||
Oil (per Bbl) | $ | 49.43 | $ | 62.28 | -20.6 | % | $ | 49.45 | $ | 59.46 | -16.8 | % | ||||||||||||||||||||||||||||
Natural gas (per Mcf) | 2.08 | 3.13 | -33.5 | % | 2.95 | 3.39 | -13.0 | % | ||||||||||||||||||||||||||||||||
Natural gas liquids (per Bbl) | 10.49 | 33.25 | -68.5 | % | 20.75 | 32.38 | -35.9 | % | ||||||||||||||||||||||||||||||||
Combined (per BOE) | 37.89 | 52.55 | -27.9 | % | 39.69 | 50.74 | -21.8 | % | ||||||||||||||||||||||||||||||||
Average unit cost per BOE: | ||||||||||||||||||||||||||||||||||||||||
Production expenses | 11.51 | 9.76 | 17.9 | % | 11.84 | 10.27 | 15.3 | % | ||||||||||||||||||||||||||||||||
Production taxes | 2.88 | 4.58 | -37.1 | % | 3.16 | 4.40 | -28.2 | % | ||||||||||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion | 14.29 | 15.01 | -4.8 | % | 13.95 | 15.28 | -8.7 | % | ||||||||||||||||||||||||||||||||
Capital expenditures | $ | 5,957,663 | $ | 440,618 | $ | 7,808,174 | $ | 7,204,900 |
Oil, Natural Gas and NGL Revenues
For the three months ended September 30, 2019, revenues for oil, natural gas and NGL sales were $7.3 million. Revenues for the sale of crude oil were $6.6 million, which resulted in a realized price of $49.43 per barrel. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $2.08 per Mcf. Revenues for the sale of NGLs were $0.3 million, which resulted in a realized price of $10.49 per BOE of sold production. For the three months ended September 30, 2018, revenues for oil, natural gas and NGL sales were $15.7 million. Revenues for the sale of crude oil were $13.6 million, which resulted in a realized price of $62.28 per barrel. Revenues for the sale of natural gas were $0.7 million, which resulted in a realized price of $3.13 per Mcf. Revenues for the sale of NGLs were $1.3 million, which resulted in a realized price of $33.25 per BOE of sold production.
For the nine months ended September 30, 2019, revenues for oil, natural gas and NGL sales were $26.7 million. Revenues for the sale of crude oil were $22.6 million, which resulted in a realized price of $49.45 per barrel. Revenues for the sale of natural gas were $2.1 million, which resulted in a realized price of $2.95 per Mcf. Revenues for the sale of NGLs were $2.1 million, which resulted in a realized price of $20.75 per BOE of sold production. For the nine months ended September 30, 2018, revenues for oil, natural gas and NGL sales were $42.2 million. Revenues for the sale of crude oil were $36.4 million, which resulted in a realized price of $59.46 per barrel. Revenues for the sale of natural gas were $2.2 million, which resulted in a realized price of $3.39 per Mcf. Revenues for the sale of NGLs were $3.5 million, which resulted in a realized price of $32.38 per BOE of sold production.
The Partnership’s results for the nine-month period ended September 30, 2019 were negatively impacted by decreases in commodity prices for oil, natural gas and NGLs, in comparison to the same period of 2018. In addition, sold oil production volumes were lower in the third quarter and nine-month period ended September 30, 2019 when compared to the same periods of 2018, which was the result of (i) natural production declines; (ii) production from some of the Partnership’s existing producing wells being temporarily suspended in the second and third quarters of 2019 due to the commencement of drilling new wells on the Partnership’s acreage; and (iii) the Partnership completing six new wells in 2018, of which all six were producing as of September 30, 2018. 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. The completion of the six wells increased sold production for the three- and nine-month periods ended September 30, 2018.
Sold production of the Partnership’s natural gas has increased for the nine months ended September 30, 2019, when compared to the same period of 2018. A customer’s gas plant was temporarily shut down for maintenance during the second quarter of 2018, which negatively impacted sold production volumes of the Partnership’s natural gas during 2018.
Production for the Sanish Field Assets was approximately 2,100 BOE and 2,500 BOE per day for the three and nine months ended September 30, 2019, while sold production for the Sanish Field Assets was approximately 3,200 BOE and 3,100 BOE for the three and nine months ended September 30, 2018. Production is dependent on the investment in existing wells and the development of new wells. If the Partnership or its operators are unable or it is not cost beneficial to invest in existing wells or develop new wells, production will decline. See discussion of the Partnership’s investment in new wells in 2019 below.
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, salt water disposal, utilities, maintenance, repairs and servicing expenses related to the Partnership’s oil and natural gas properties, along with the gathering and processing contract in effect for the extraction, transportation and treatment of natural gas.
For the three months ended September 30, 2019 and 2018, production expenses were $2.2 million and $2.9 million, respectively, and production expenses per BOE of sold production were $11.51 and $9.76, respectively. For the nine months ended September 30, 2019 and 2018, production expenses were $8.0 million and $8.5 million, respectively, and production expenses per BOE of sold production were $11.84 and $10.27, respectively. The decrease in sold production volumes along with fixed lease operating expenses contributed to the increase in production expenses per BOE of sold production for the three and nine months ended September 30, 2019, compared to same periods in 2018.
Production Taxes
Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Production taxes for the three months ended September 30, 2019 and 2018 were $0.6 million (7.6% of revenue) and $1.4 million (8.7% of revenue), respectively. Production taxes for the nine months ended September 30, 2019 and 2018 were $2.1 million (8.0% of revenue) and $3.7 million (8.7% of revenue), respectively. Production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGL to total sales. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil.
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 September 30, 2019 and 2018 was $2.8 million and $4.5 million, and DD&A per BOE of sold production was $14.29 and $15.01, respectively. DD&A for the nine months ended September 30, 2019 and 2018 was $9.4 million and $12.7 million, and DD&A per BOE of sold production was $13.95 and $15.28, respectively.
The decrease in 2019 DD&A expense per BOE of production compared to 2018 DD&A expense per BOE of production is primarily due to the increase of the Partnership’s estimated proved undeveloped reserves resulting from changes in the future drill schedule.
General and Administrative Costs
General and administrative costs for the three months ended September 30, 2019 and 2018 were $0.3 million in both periods. General and administrative costs for the nine months ended September 30, 2019 and 2018 were $1.0 million in both periods. The principal components of general and administrative expense are accounting, legal and consulting fees.
Gain (Loss) on Derivatives
In September 2019, the Partnership entered into a derivative contract (costless collar) with the objective to manage the commodity price risk on a portion of anticipated oil production for the six-month period from October 1, 2019 to March 31, 2020. As of September 30, 2019, the Partnership’s derivative contract (costless collar) was in a gain position based upon the contract’s estimated fair market value at the balance sheet date. Based upon the estimated fair value of the derivative contract as of September 30, 2019, the Partnership recorded a mark-to-market gain of approximately $0.5 million. Changes in the fair value of the unsettled derivative contracts represent mark-to-market gains and losses and are recorded on the Partnership’s consolidated statements of operations. The mark-to-market gain recorded by the Partnership in the third quarter of 2019 does not represent an actual settlement and no payment was made to the counterparty during the third quarter of 2019.
In December 2017, January 2018 and March 2018, the Partnership entered into derivative contracts (costless collars) to manage the commodity price risk on a portion of anticipated 2018 oil production. The Partnership’s loss on derivative instruments for the three months ended September 30, 2018 was approximately $40,000. The loss is comprised of (i) $1.10 million of losses on settled derivatives during the period, offset by (ii) $1.06 million of a mark-to-market gain on derivative instruments outstanding at period end. The Partnership’s recognized losses on settled derivatives of $1.1 million represented 108,000 barrels of produced oil, resulting in a loss of $10.19 per barrel of oil. The Partnership’s loss on derivative instruments for the nine months ended September 30, 2018 was $2.9 million. The loss is comprised of (i) $2.5 million of losses on settled derivatives during the period, and (ii) $0.4 million of a mark-to-market loss incurred on derivative instruments outstanding at period end. The Partnership’s recognized losses on settled derivatives of $2.5 million represented 324,000 barrels of produced oil, resulting in a loss of $7.82 per barrel of oil.
The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s oil production from October 1, 2019 to March 31, 2020.
Costless Collar Volumes | Floor / Ceiling Prices ($) | |||||||
10/01/19 - 03/31/20 | 167,000 | 55.00 / 59.25 |
Interest Expense, Net
Interest expense, net, for the three months ended September 30, 2019 and 2018 was $0.2 million in both periods. Interest expense, net, for the nine months ended September 30, 2019 and 2018 was $0.6 million in both periods. The primary component of Interest expense, net, during the three- and nine-month periods ended September 30, 2019 and 2018 was interest expense on the Credit Facility. Although interest rates have declined, the Partnership expects its interest expense to increase in the fourth quarter of 2019 due to an increase in outstanding borrowings.
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 Company’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 nine months ended September 30, 2019 and 2018.
Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||
Net income | $ | 1,794,044 | $ | 6,360,110 | $ | 6,093,081 | $ | 12,720,479 | ||||||||
Interest expense, net | 207,847 | 183,480 | 598,063 | 574,127 | ||||||||||||
Depreciation, depletion, amortization and accretion | 2,767,479 | 4,481,712 | 9,403,364 | 12,705,908 | ||||||||||||
Exploration expenses | - | - | - | - | ||||||||||||
Non-cash (gain) loss on mark-to-market of derivatives | (498,790 | ) | (1,061,761 | ) | (498,790 | ) | 410,768 | |||||||||
Adjusted EBITDAX | $ | 4,270,580 | $ | 9,963,541 | $ | 15,595,718 | $ | 26,411,282 |
Liquidity and Capital Resources
The Partnership’s principal sources of liquidity are cash on hand, the cash flow generated from properties the Partnership has acquired and availability under the Partnership’s revolving credit facility, discussed below. The Partnership anticipates that cash on hand, cash flow from operations and availability under the revolving credit facility will be adequate to meet its anticipated liquidity requirements for at least the next 12 months, including completing capital expenditures discussed below.
Financing
On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”), which provided for a revolving credit facility with an approved initial commitment amount of $20 million, subject to borrowing base restrictions. The maturity date was November 21, 2019.
Effective September 30, 2019, the Partnership entered into an amendment and restatement of the Loan Agreement (the “Amended Loan Agreement”), which provides for a revolving credit facility (“Credit Facility”) with an approved initial commitment of $40 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The terms of the Amended Loan Agreement are generally similar to the Partnership’s existing revolving credit facility and include the following: (i) a maturity date of September 30, 2022; (ii) subject to certain exceptions, an interest rate, which did not change from the existing revolving credit facility, equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.50% to 3.50%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Amended Loan Agreement; (iii) an increase to the borrowing base from $30 million to an initially stipulated $40 million; and (iv) an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties. The Revolver Commitment Amount may be increased up to $75 million with lender approval.
At September 30, 2019, the outstanding balance on the Credit Facility was $16.8 million, the borrowing base was $40 million, and the interest rate for the Credit Facility was approximately 4.87%. Outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Revolver Commitment Amount at any time.
At closing in October 2019, the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000, and is subject to origination fees of 0.45% for any borrowings made in excess of the Revolver Commitment Amount. The Partnership is also required to pay an unused facility fee of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter.
If certain conditions set forth in the Amended Loan Agreement are met, the Partnership will be required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production. If these conditions are met, the risk management program must cover at least 50% of the Partnership’s projected total production of oil and natural gas for a rolling 18-month period.
The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include:
- | A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00 |
- | A minimum ratio of current assets to current liabilities of 1.00 to 1.00 |
- | A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period |
- | A limit to Partnership distributions if certain terms and conditions are not met, including being limited to 50% of the previous quarter EBITDAX beginning April 1, 2020. |
The Partnership was in compliance with the applicable covenants at September 30, 2019.
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
For the three and nine months ended September 30, 2019, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $6.6 million and $19.9 million, respectively. For the three and nine months ended September 30, 2018, the Partnership paid distributions of $0.413424 and $1.081643 per common unit, or $7.8 million and $20.5 million, respectively. The Partnership generated $16.8 million and $24.0 million, respectively, in cash flow from operating activities for the nine months ended September 30, 2019 and 2018. The Partnership’s ability to maintain the current distribution of $1.40 per common unit per year will be based on its ability to increase cash flow from operating activities. In addition, as discussed in Financing above, the terms of the Amended Loan Agreement may limit the Partnership’s distributions if certain terms and conditions are not met. Specifically, among other terms, the Partnership’s distributions may be limited to 50% of the previous quarter EBITDAX beginning April 1, 2020.
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, capital expenditures for new wells and debt service.
Oil and Natural Gas Properties
The Partnership incurred approximately $7.8 million and $7.2 million in capital expenditures for the nine months ended September 30, 2019 and 2018, respectively. The Partnership expects to invest approximately $40 to $50 million in capital expenditures during the next twelve months from September 30, 2019, which includes an estimated $24 million to fund all remaining drilling and completion costs associated with the 19 wells in which the Partnership has elected to participate, including the one well already completed and the remaining 18 wells in progress.. The Partnership anticipates Whiting will commence drilling on approximately 7 additional wells on the Partnership’s acreage during the fourth quarter of 2019. Inclusive of Whiting’s current drilling program, the Partnership anticipates that it may be obligated to invest $65 to $70 million in drilling capital expenditures from 2020 through 2023 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.
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 and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for the remainder of 2019 and into 2020. 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 provided by operating activities, cash on hand and availability under the Credit Facility. 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.
See further discussion in “Note 9. Related Parties” in Part I, Item 1 of this Form 10-Q.
Subsequent Events
In October 2019, the Partnership entered into an amendment and restatement of its existing revolving credit facility, effective September 30, 2019. At closing, the Partnership borrowed an incremental $0.2 million under the restated Credit Facility to pay closing costs. See further discussion above in Liquidity and Capital Resources: Financing.
In October 2019, the Partnership declared and paid $2.0 million, or $0.107397 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 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.
The Partnership has a variable interest rate on its Credit Facility that is subject to market changes in interest rates. Information regarding the Partnership’s 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.
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, 2019 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, 2019 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 2018 Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2018 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 |
10.7 |
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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 |
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32.2 |
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101 |
| The following materials from Energy 11, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Cover Page, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Operations, (iv) the Consolidated Statements of Partners’ Equity, (v) the Consolidated Statements of Cash Flows, and (iv) 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 September 30, 2019, 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 |
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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 8, 2019 |
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