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, |
☐ | 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.) |
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)
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of each exchange on which registered |
None |
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 ☐ | Accelerated filer ☐ | |||
Non-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 ☐ No ☑
As of November 5, 2020,12, 2021, the Partnership had 18,973,474 common units outstanding.
Energy 11, L.P.
Form 10-Q
Index
Page Number | |||
PART I. FINANCIAL INFORMATION | |||
Item 1. | |||
Consolidated Balance Sheets – September 30, | 3 | ||
4 | |||
5 | |||
Consolidated Statements of Cash Flows – Nine months ended September 30, | 6 | ||
7 | |||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 3. |
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Item 4. |
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PART II. OTHER INFORMATION | |||
Item 1. |
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Item 1A. |
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Item 2. |
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Item 3. |
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Item 4. |
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Item 5. |
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Item 6. |
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Energy 11, L.P.
Consolidated Balance Sheets
September 30, | December 31, | September 30, | December 31, | |||||||||||||
2020 | 2019 | 2021 | 2020 | |||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Assets | ||||||||||||||||
Cash and cash equivalents | $ | 5,254,981 | $ | 348,550 | $ | - | $ | 1,608,301 | ||||||||
Restricted cash and cash equivalents | 1,288,884 | 0 | - | 855,518 | ||||||||||||
Oil, natural gas and natural gas liquids revenue receivable | 4,714,775 | 5,857,926 | ||||||||||||||
Other current assets | 418,001 | 284,652 | ||||||||||||||
Accounts receivable | 14,181,024 | 5,890,971 | ||||||||||||||
Other current assets, net | 377,590 | 257,524 | ||||||||||||||
Total Current Assets | 11,676,641 | 6,491,128 | 14,558,614 | 8,612,314 | ||||||||||||
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $69,699,954 and $53,186,165, respectively | 328,844,767 | 326,758,636 | ||||||||||||||
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $92,088,477 and $75,765,289, respectively | 324,708,203 | 323,200,183 | ||||||||||||||
Other assets | 201,058 | - | ||||||||||||||
Total Assets | $ | 340,521,408 | $ | 333,249,764 | $ | 339,467,875 | $ | 331,812,497 | ||||||||
Liabilities | ||||||||||||||||
Accounts payable, accrued expenses and other current liabilities | $ | 3,208,326 | $ | 20,061,059 | ||||||||||||
Revolving credit facility | 40,000,000 | 0 | $ | - | $ | 40,000,000 | ||||||||||
Affiliate term loan | 15,000,000 | 0 | - | 6,000,000 | ||||||||||||
Accounts payable and accrued expenses | 6,496,523 | 3,299,810 | ||||||||||||||
Derivative liability | 1,055,525 | 602,760 | ||||||||||||||
Total Current Liabilities | 58,208,326 | 20,061,059 | 7,552,048 | 49,902,570 | ||||||||||||
Revolving credit facility | 0 | 24,000,000 | 34,000,000 | - | ||||||||||||
Asset retirement obligations | 1,549,927 | 1,452,734 | 1,761,757 | 1,564,105 | ||||||||||||
Derivative liability - noncurrent | 1,175,079 | - | ||||||||||||||
Total Liabilities | 59,758,253 | 45,513,793 | 44,488,884 | 51,466,675 | ||||||||||||
Partners’ Equity | ||||||||||||||||
Partners’ Equity | ||||||||||||||||
Limited partners' interest (18,973,474 common units issued and outstanding, respectively) | 280,764,882 | 287,737,698 | 294,980,718 | 280,347,549 | ||||||||||||
General partner's interest | (1,727 | ) | (1,727 | ) | (1,727 | ) | (1,727 | ) | ||||||||
Class B Units (62,500 units issued and outstanding, respectively) | 0 | 0 | - | - | ||||||||||||
Total Partners’ Equity | 280,763,155 | 287,735,971 | 294,978,991 | 280,345,822 | ||||||||||||
Total Liabilities and Partners’ Equity | $ | 340,521,408 | $ | 333,249,764 | $ | 339,467,875 | $ | 331,812,497 |
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 | Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||||||||||||||
September 30, 2020 | September 30, 2019 | September 30, 2020 | September 30, 2019 | September 30, 2021 | September 30, 2020 | September 30, 2021 | September 30, 2020 | |||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||||||
Oil | $ | 8,187,180 | $ | 6,649,652 | $ | 22,412,183 | $ | 22,612,030 | $ | 17,888,207 | $ | 8,187,180 | $ | 40,358,354 | $ | 22,412,183 | ||||||||||||||||
Natural gas | 636,971 | 429,347 | 1,392,651 | 2,066,813 | 1,269,296 | 636,971 | 3,613,282 | 1,392,651 | ||||||||||||||||||||||||
Natural gas liquids | 826,117 | 260,110 | 1,701,486 | 2,069,270 | 1,835,202 | 826,117 | 4,504,618 | 1,701,486 | ||||||||||||||||||||||||
Total revenue | 9,650,268 | 7,339,109 | 25,506,320 | 26,748,113 | 20,992,705 | 9,650,268 | 48,476,254 | 25,506,320 | ||||||||||||||||||||||||
Operating costs and expenses | ||||||||||||||||||||||||||||||||
Production expenses | 2,825,472 | 2,228,933 | 6,997,839 | 7,977,046 | 2,747,487 | 2,825,472 | 8,270,708 | 6,997,839 | ||||||||||||||||||||||||
Production taxes | 777,012 | 558,288 | 2,185,903 | 2,132,056 | 1,653,661 | 777,012 | 3,749,060 | 2,185,903 | ||||||||||||||||||||||||
General and administrative expenses | 379,569 | 281,308 | 1,300,003 | 1,043,293 | 325,168 | 379,569 | 1,172,298 | 1,300,003 | ||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion | 6,112,621 | 2,767,479 | 16,575,336 | 9,403,364 | 6,547,607 | 6,112,621 | 16,387,823 | 16,575,336 | ||||||||||||||||||||||||
Total operating costs and expenses | 10,094,674 | 5,836,008 | 27,059,081 | 20,555,759 | 11,273,923 | 10,094,674 | 29,579,889 | 27,059,081 | ||||||||||||||||||||||||
Operating income (loss) | (444,406 | ) | 1,503,101 | (1,552,761 | ) | 6,192,354 | 9,718,782 | (444,406 | ) | 18,896,365 | (1,552,761 | ) | ||||||||||||||||||||
Gain on derivatives | 94,299 | 498,790 | 535,189 | 498,790 | ||||||||||||||||||||||||||||
Gain (loss) on derivatives, net | (2,230,604 | ) | 94,299 | (2,810,264 | ) | 535,189 | ||||||||||||||||||||||||||
Interest expense, net | (529,789 | ) | (207,847 | ) | (1,370,418 | ) | (598,063 | ) | (445,388 | ) | (529,789 | ) | (1,452,932 | ) | (1,370,418 | ) | ||||||||||||||||
Total other expense, net | (435,490 | ) | 290,943 | (835,229 | ) | (99,273 | ) | (2,675,992 | ) | (435,490 | ) | (4,263,196 | ) | (835,229 | ) | |||||||||||||||||
Net income (loss) | $ | (879,896 | ) | $ | 1,794,044 | $ | (2,387,990 | ) | $ | 6,093,081 | $ | 7,042,790 | $ | (879,896 | ) | $ | 14,633,169 | $ | (2,387,990 | ) | ||||||||||||
Basic and diluted net income (loss) per common unit | $ | (0.05 | ) | $ | 0.09 | $ | (0.13 | ) | $ | 0.32 | $ | 0.37 | $ | (0.05 | ) | $ | 0.77 | $ | (0.13 | ) | ||||||||||||
Weighted average common units outstanding - basic and diluted | 18,973,474 | 18,973,474 | 18,973,474 | 18,973,474 | 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’Partners’ Equity
(Unaudited)
Limited Partner | Class B | General Partner | Total Partners' | |||||||||||||||||||||
Common Units | Amount | Units | Amount | Amount | Equity | |||||||||||||||||||
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 ($0.369041 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 | |||||||||||||
Balances - December 31, 2019 | 18,973,474 | $ | 287,737,698 | 62,500 | $ | - | $ | (1,727 | ) | $ | 287,735,971 | |||||||||||||
Distributions declared and paid to common units ($0.241644 per common unit) | - | (4,584,826 | ) | - | - | - | (4,584,826 | ) | ||||||||||||||||
Net income - three months ended March 31, 2020 | - | 2,933,427 | - | - | - | 2,933,427 | ||||||||||||||||||
Balances - March 31, 2020 | 18,973,474 | 286,086,299 | 62,500 | - | (1,727 | ) | 286,084,572 | |||||||||||||||||
Net loss - three months ended June 30, 2020 | - | (4,441,521 | ) | - | - | - | (4,441,521 | ) | ||||||||||||||||
Balances - June 30, 2020 | 18,973,474 | 281,644,778 | 62,500 | - | (1,727 | ) | 281,643,051 | |||||||||||||||||
Net loss - three months ended September 30, 2020 | - | (879,896 | ) | - | - | - | (879,896 | ) | ||||||||||||||||
Balances - September 30, 2020 | 18,973,474 | $ | 280,764,882 | 62,500 | $ | - | $ | (1,727 | ) | $ | 280,763,155 |
Limited Partner | Class B | General Partner | Total Partners' | |||||||||||||||||||||
Common Units | Amount | Units | Amount | Amount | Equity | |||||||||||||||||||
Balances - December 31, 2019 | 18,973,474 | $ | 287,737,698 | 62,500 | $ | - | $ | (1,727 | ) | $ | 287,735,971 | |||||||||||||
Distributions declared and paid to common units ($0.241644 per common unit) | - | (4,584,826 | ) | - | - | - | (4,584,826 | ) | ||||||||||||||||
Net income - three months ended March 31, 2020 | - | 2,933,427 | - | - | - | 2,933,427 | ||||||||||||||||||
Balances - March 31, 2020 | 18,973,474 | 286,086,299 | 62,500 | - | (1,727 | ) | 286,084,572 | |||||||||||||||||
Net loss - three months ended June 30, 2020 | - | (4,441,521 | ) | - | - | - | (4,441,521 | ) | ||||||||||||||||
Balances - June 30, 2020 | 18,973,474 | $ | 281,644,778 | 62,500 | $ | - | $ | (1,727 | ) | $ | 281,643,051 | |||||||||||||
Net loss - three months ended September 30, 2020 | - | (879,896 | ) | - | - | - | (879,896 | ) | ||||||||||||||||
Balances - September 30, 2020 | 18,973,474 | 280,764,882 | 62,500 | - | (1,727 | ) | 280,763,155 | |||||||||||||||||
Balances - December 31, 2020 | 18,973,474 | $ | 280,347,549 | 62,500 | $ | - | $ | (1,727 | ) | $ | 280,345,822 | |||||||||||||
Net income - three months ended March 31, 2021 | - | 3,463,469 | - | - | - | 3,463,469 | ||||||||||||||||||
Balances - March 31, 2021 | 18,973,474 | 283,811,018 | 62,500 | - | (1,727 | ) | 283,809,291 | |||||||||||||||||
Net income - three months ended June 30, 2021 | - | 4,126,910 | - | - | - | 4,126,910 | ||||||||||||||||||
Balances - June 30, 2021 | 18,973,474 | $ | 287,937,928 | 62,500 | $ | - | $ | (1,727 | ) | $ | 287,936,201 | |||||||||||||
Net income - three months ended September 30, 2021 | - | 7,042,790 | - | - | - | 7,042,790 | ||||||||||||||||||
Balances - September 30, 2021 | 18,973,474 | $ | 294,980,718 | 62,500 | $ | - | $ | (1,727 | ) | $ | 294,978,991 |
See notes to consolidated financial statements.
Energy 11, L.P.
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended | Nine Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||
September 30, 2020 | September 30, 2019 | September 30, 2021 | September 30, 2020 | |||||||||||||
Cash flow from operating activities: | ||||||||||||||||
Net income (loss) | $ | (2,387,990 | ) | $ | 6,093,081 | $ | 14,633,169 | $ | (2,387,990 | ) | ||||||
Adjustments to reconcile net income to cash from operating activities: | ||||||||||||||||
Adjustments to reconcile net income (loss) to cash from operating activities: | ||||||||||||||||
Depreciation, depletion, amortization and accretion | 16,575,336 | 9,403,364 | 16,387,823 | 16,575,336 | ||||||||||||
Gain on mark-to-market of derivatives | (250,149 | ) | (498,790 | ) | ||||||||||||
(Gain) loss on mark-to-market of derivatives, net | 1,627,844 | (250,149 | ) | |||||||||||||
Non-cash expenses, net | 67,232 | 37,328 | 167,416 | 67,232 | ||||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Oil, natural gas and natural gas liquids revenue receivable | 1,143,151 | 2,412,723 | ||||||||||||||
Other current assets | (134,283 | ) | (36,170 | ) | ||||||||||||
Accounts payable, accrued expenses and other current liabilities | 39,550 | (603,796 | ) | |||||||||||||
Accounts receivable | (8,290,053 | ) | 1,143,151 | |||||||||||||
Other assets | (86,423 | ) | (134,283 | ) | ||||||||||||
Accounts payable and accrued expenses | (446,167 | ) | 39,550 | |||||||||||||
Net cash flow provided by operating activities | 15,052,847 | 16,807,740 | 23,993,609 | 15,052,847 | ||||||||||||
Cash flow from investing activities: | ||||||||||||||||
Additions to oil and natural gas properties | (35,272,706 | ) | (3,540,372 | ) | (14,055,311 | ) | (35,272,706 | ) | ||||||||
Net cash flow used in investing activities | (35,272,706 | ) | (3,540,372 | ) | (14,055,311 | ) | (35,272,706 | ) | ||||||||
Cash flow from financing activities: | ||||||||||||||||
Proceeds from revolving credit facility | 16,000,000 | 3,000,000 | ||||||||||||||
Proceeds from affiliate term loan | 15,000,000 | 0 | ||||||||||||||
Cash paid for loan costs | (402,117 | ) | - | |||||||||||||
Net proceeds from (payments on) BancFirst revolving credit facility | 34,000,000 | - | ||||||||||||||
Proceeds from (payments on) Simmons revolving credit facility | (40,000,000 | ) | 16,000,000 | |||||||||||||
Proceeds from (payments on) affiliate term loan | (6,000,000 | ) | 15,000,000 | |||||||||||||
Distributions paid to limited partners | (4,584,826 | ) | (19,867,561 | ) | - | (4,584,826 | ) | |||||||||
Net cash flow provided by (used in) financing activities | 26,415,174 | (16,867,561 | ) | (12,402,117 | ) | 26,415,174 | ||||||||||
Increase (decrease) in cash, cash equivalents and restricted cash | 6,195,315 | (3,600,193 | ) | (2,463,819 | ) | 6,195,315 | ||||||||||
Cash, cash equivalents and restricted cash, beginning of period | 348,550 | 3,685,327 | 2,463,819 | 348,550 | ||||||||||||
Cash, cash equivalents and restricted cash, end of period | $ | 6,543,865 | $ | 85,134 | $ | - | $ | 6,543,865 | ||||||||
Interest paid | $ | 1,336,840 | $ | 574,334 | $ | 1,146,956 | $ | 1,336,840 | ||||||||
Supplemental non-cash information: | ||||||||||||||||
Accrued capital expenditures related to additions to oil and natural gas properties | $ | 1,714,900 | $ | 4,366,105 | $ | 5,174,707 | $ | 1,714,900 |
See notes to consolidated financial statements.
Energy 11, L.P.
Notes to Consolidated Financial Statements
September 30, 20202021
(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, 2020,2021, the Partnership owned an approximate 25% non-operated working interest in 243264 producing wells, an estimated approximate 18%20% non-operated working interest in 2114 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 Petroleum Corporation (“Whiting”) (NYSE: WLL) and Oasis Petroleum North America, LLC (“Oasis”) (NYSE: OAS), two of the largest producers in the basin, operateoperates 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.
Drilling Program, Oil Demand, Current Pricing, Liquidity and Going Concern Considerations
During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. The Partnership estimates the total investment for these 43 new wells to be approximately $63 million. In conjunction with this drilling program performed primarily by Whiting, the Partnership had incurred approximately $42 million in capital expenditures through September 30, 2020, which was primarily funded by availability under the Partnership’s $40 million revolving credit facility (“Credit Facility”, described in Note 4. Debt). However, the Partnership used all availability under its Credit Facility by March 31, 2020, and as of June 30, 2020, the Partnership had approximately $20 million in accrued operating and capital expenditures due to Whiting. New production from completed wells was expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage.
Subsequent to the Partnership’s election to participate in Whiting’s drilling program, the outbreak of a novel coronavirus (“COVID-19”) in China spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries for an undetermined period of time, creating extreme volatility in capital markets and the global economy. Because of COVID-19’s impact to the global economy, demand for oil, natural gas and other hydrocarbons substantially declined in March 2020 and has remained depressed through the third quarter of 2020. Demand for oil and natural gas is not anticipated to return to pre-COVID-19 levels during 2020, and the outlook for demand for oil and natural gas in 2021 is uncertain. This reduction in demand compounded an existing excess in supply of oil and natural gas, as the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia could not agree on daily production output of crude oil in March 2020. As a result, Russia announced its intention to increase production, and Saudi Arabia immediately countered with announced reductions to export prices. All of these factors led to oil prices falling in March 2020 and to 20-year lows in April 2020. Although NYMEX oil prices have stabilized around $40 per barrel since June 2020, prices throughout the third quarter of 2020 remained below pre-COVID-19 levels.
In response to lower commodity prices and reduced demand, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs, and implemented other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. While operators have since returned significant inventory of existing wells to production, the nature and timing of drilling new wells remains uncertain. These factors have had and are anticipated to continue to have an adverse impact on the Partnership’s business and its financial condition. Due to the impacts to the global oil and gas industry described above, the General Partner approved the suspension of distributions to limited partners of the Partnership in March 2020. Further, Whiting and certain of its subsidiaries declared bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas on April 1, 2020. Subsequent to filing for Chapter 11 protection, Whiting suspended its Sanish field drilling program during the second quarter of 2020, but operated its business in the normal course without material disruption to its vendors, partners or employees, including the Partnership, during the bankruptcy process. Whiting completed its financial restructuring and emerged from bankruptcy protection in September 2020, but has yet to resume its drilling program.
In July 2020, the Partnership entered into a loan agreement for a one year, $15 million term loan (“Affiliate Loan”) that matures on July 21, 2021 (see Note 4. Debt for additional information). The Partnership used proceeds from the Affiliate Loan plus cash on hand to pay the Partnership’s accrued operating and capital expenditures due to Whiting, which totaled approximately $19 million at the time of payment. In addition to the Affiliate Loan, the Partnership entered into a letter agreement (“Letter Agreement”) with its lending group for its Credit Facility. The Letter Agreement, among other items, waived the non-compliance of certain covenants under the Credit Facility; however, the Letter Agreement changed the maturity date of the Credit Facility from September 30, 2022 to July 31, 2021. In October 2020, the Partnership made a principal payment on the Affiliate Loan of $5 million; therefore, the Partnership’s outstanding debt obligations at the date of filing of this Form 10-Q total $50 million and mature within one year of the filing of this Form 10-Q.
The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) the Partnership’s ability to comply with its obligations under its loan agreements (see Note 4. Debt for further discussion); (ii) refinancing its existing debt and/or securing additional capital; (iii) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (iv) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Refinancing its existing debt or securing additional capital may not be available on favorable terms to the Partnership, if it is available at all. There also can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will return to pre-COVID-19 levels, or that the Partnership will be able to meet its operational obligations. If the Partnership is unable to refinance or repay its debt obligations or is unable to meet its operational obligations, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy these obligations, which create the substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued.
The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Partnership to continue as a going concern.
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 20192020 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 20202021 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2020.2021.
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 Oil, natural gas and natural gas liquids revenueAccounts 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 (Loss) Per Common Unit
Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were 0no common units with a dilutive effect for the three and nine months ended September 30, 20202021 and 2019.2020. 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 (loss) per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.
Recently Adopted Accounting Standards
In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of September 30, 2020.
Note 3. Oil and Natural Gas Investments
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.
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.
DuringSince the beginning of 2019, and the first quarter of 2020, the Partnership has elected to participate in the drilling and completion of 4357 new wells in the Sanish field. NaN (22)(43) of these 4357 wells have been completed and were producing at September 30, 2020;2021; the Partnership has an approximate non-operated working interest of 23%21% in these 2243 wells. The Partnership has an estimated approximate non-operated working interest of 18%20% in the remaining 218 wells that are in-process as of September 30, 2020.2021. The Partnership has an estimated approximate non-operated working interest of 20% in 6 wells that had not commenced drilling as of September 30, 2021. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 4357 wells is approximately $63$75 million, of which approximately $42$56 million was incurred as of September 30, 2020. Whiting suspended its Sanish field drilling program during the second quarter of 2020 in response to the significant reduction in demand for oil caused by COVID-19 and the oversupply of oil in the United States.2021. The Partnership estimates it may incur approximately $1the approximate $15 to $220 million in additional capital expenditures duringto complete the remaining 14 wells will be incurred over the fourth quarter of 2020; however, low commodity prices, market supply2021 and demand imbalances and how Whiting’s emergencethe first half of 2022 based on the best available information regarding current capital investment plans from bankruptcy protection in September 2020 impactsits operators. However, many factors outside the resumption of its suspended drilling programPartnership’s control make it difficult to predict the amount and timing of capital expenditures, for the remainder of 2020. Estimatedand estimated capital expenditures could be significantly different from amounts actually invested.
Evaluation for Potential Impairment of Oil and Natural Gas Investments
The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. The Partnership considered the declines in the current and forecasted operating cash flows resulting from COVID-19 and sustained lower commodity prices to be potential indicators of impairment and, as a result, performed a test of recoverability for the Sanish Field Assets. Estimated future net cash flows calculated in the recoverability test were based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows were based on NYMEX forward strip prices as of October 1, 2020, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believed will impact realizable prices. Future operating cost estimates were based on actual historical costs of the Sanish Field Assets. The Partnership’s recoverability analyses did not identify any impairment losses as of September 30, 2020.
If current macro-economic conditions continue or worsen, the carrying value of the Partnership’s oil and natural gas properties may not be recoverable and impairment losses could be recorded in future periods.
Note 4. Debt
Revolving Credit FacilityFacilities
OnIn November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan“Simmons Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto (the “Lender”), whichthereto. Through various amendments, the Simmons Loan Agreement provided for a revolving credit facility (“Simmons Credit Facility”) with a commitment amount of $40 million, subject to borrowing base restrictions, that was to mature on July 31, 2021. The Simmons Credit Facility had an interest rate of 4.25% and outstanding borrowings of $40 million as of May 13, 2021.
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 initial commitmentmaximum credit amount (“Maximum Credit Amount”) of $20$60 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”) with Lender, which provided for the 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 were generally similar to the Partnership’s existing revolving credit facility and included 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.
At closing of the Amended Loan Agreement in October 2019, the Partnership paid an origination fee of 0.45%0.50% of the Maximum Credit Amount, or $300,000, and is subject to an additional fee of 0.25% on any incremental increase to the borrowing base. Total capitalized loan costs were approximately $0.4 million and are being amortized over the life of the BF Credit Facility. Approximately $0.1 million of the deferred loan costs are recorded as Other current assets, net and the other approximate $0.2 million in deferred loan costs are recorded as Other assets on the change in Revolver Commitment AmountPartnership’s consolidated balance sheet as 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.September 30, 2021. The Partnership also is also required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.50%0.25% on the unused portion of the Revolver Commitment Amount,Revolving Credit Facility, based on the amount of borrowings outstanding during a quarter.
On July 21, 2020, the Partnership entered into a letter agreement (“Letter Agreement”) with Lender that amended and modified the Amended Loan Agreement. The modifications to the Amended Loan Agreement include, among other items, the following:maturity date is March 1, 2024.
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At closing, the Partnership borrowed approximately $40 million. The proceeds were used to pay the $40 million outstanding balance and accrued interest on the Simmons Credit Facility described above. Any further advances under the BF Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the BF Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.
Under the BF Loan Agreement, the initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which was initially stipulated to be $1 million. Therefore, as of September 30, 2021, the borrowing base was $56 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. The Lender did not make adjustments to the Partnership’s borrowing base or the Monthly Commitment Reduction provision based on its September 1, 2021 redetermination analysis. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period. Outstanding borrowings under the BF Credit Facility cannot exceed the lesser of the borrowing base or the Maximum Credit Amount at any time. The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.00%.
Also under the LetterBF Loan Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and natural gas sales.production. The risk management programPartnership must coverhedge at least 80%50% of its rolling 12-month projected future production if the Partnership’s utilization of the Partnership’s projected total productionRevolving Credit Facility is less than 50% of oil and natural gas for the period from August 31, 2020 untillesser of the next(i) Maximum Credit Amount or (ii) current borrowing base, redetermination date (first quarterand at least 50% of 2021).its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 50% of the lesser of the (i) Maximum Credit Amount or (ii) current borrowing base. See Note 7. Risk Management for more information on the Partnership’s hedgingrisk management program in Note 7. Risk Management.
In addition to the modification of certain termsas required under the AmendedBF Loan Agreement, the Letter Agreement waived the defaults by the Partnership under the Amended Loan Agreement that existed prior to signing the Letter Agreement, including not meeting the current ratio covenant as of March 31, 2020, the Partnership not filing its first quarter financial statements within 60 days of March 31, 2020 and the non-payment by the Partnership of amounts due to Whiting. The Letter Agreement also waived the Partnership’s calculation of the current ratio covenant at June 30, 2020. The Letter Agreement also allows for the Affiliate Loan discussed below and payments under the Affiliate Loan.
In consideration for the modifications, amendments and waivers described above to the Amended Loan Agreement, the Letter Agreement provides for an amendment fee to Lender of $40,000, of which $15,000 was paid on September 30, 2020 and $25,000 is due December 31, 2020.Agreement.
The BF 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 |
● | A minimum ratio of current assets to current liabilities of 1.00 to 1.00 | |
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The BF Loan Agreement restricts the Partnership’s ability to pay limited partner distributions until the outstanding balance of the BF Credit Facility is equal to or less than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base, at which point 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.
The Partnership was in compliance with its applicable covenants at September 30, 2020. If the Partnership is not in compliance with its covenants in future periods, it may not be able to obtain waivers and the outstanding balance under the Credit Facility may become due on demand at that time.2021.
At September 30, 2020,2021, the outstanding balance on the BF Credit Facility was $40approximately $34 million, and the interest rate for the Credit Facility was 4.25%4.00%. As of September 30, 20202021 and December 31, 2019,2020, the outstanding balances on the BF Credit Facility and the Simmons Credit Facility were $40approximately $34 million and $24$40 million, respectively, which approximateapproximated the fair market value.value of each credit facility. The Partnership estimated the fair value of its Credit Facilitycredit facilities 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.
Term Loan from Affiliate
On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which providesprovided for an unsecured, one-year term loan (“Term Loan” or “Affiliate Loan”) in the amount of $15 million. GKDML is owned and managed by Glade M. Knight and David S. McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. The Term Loan bearswas repaid in full during March 2021, and the Partnership did not incur a penalty for prepayment. The Term Loan bore interest at a variable rate based on LIBOR plus a margin of 2.00%, with a LIBOR floor of 0%. Interest iswas payable monthly. The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. At September 30, 2020, the outstanding balance on the Term Loan was $15 million, the interest rate for the Term Loan was approximately 2.2% and the Partnership was in compliance of all applicable covenants.
To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A. on July 21, 2020 (“GKDML Loan”). The GKDML Loan haswas also repaid in March 2021, had substantially the same terms as the Term Loan and iswas personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and willdid not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimbursereimbursed GKDML for all costs of the GKDML Loan. The Term Loan may be prepaid at any time with no penalty and in any amount, but any amounts repaid may not be reborrowed.
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:
2020 | 2019 | 2021 | 2020 | |||||||||||||
Balance at January 1 | $ | 1,452,734 | $ | 1,294,067 | $ | 1,564,105 | $ | 1,452,734 | ||||||||
Well additions | 35,646 | 73,096 | 133,016 | 35,646 | ||||||||||||
Accretion | 61,547 | 52,482 | 64,636 | 61,547 | ||||||||||||
Revisions | 0 | 0 | - | - | ||||||||||||
Balance at September 30 | $ | 1,549,927 | $ | 1,419,645 | $ | 1,761,757 | $ | 1,549,927 |
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, 20202021 and 2019,2020, 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, 20202021 and December 31, 2019.2020.
Fair Value Measurements at September 30, 2020 | Fair Value Measurements at September 30, 2021 | |||||||||||||||||||||||
Quoted Prices in | Significant Other Observable Inputs | Significant Unobservable Inputs | Quoted Prices in | Significant Other Observable Inputs | Significant Unobservable Inputs | |||||||||||||||||||
Commodity derivatives - current assets | $ | 0 | $ | 66,299 | $ | 0 | ||||||||||||||||||
Commodity derivatives - current liabilities | $ | - | $ | (1,055,525 | ) | $ | - | |||||||||||||||||
Commodity derivatives - non-current liabilities | - | (1,175,079 | ) | - | ||||||||||||||||||||
Total | $ | 0 | $ | 66,299 | $ | 0 | $ | - | $ | (2,230,604 | ) | $ | - |
Fair Value Measurements at December 31, 2019 | Fair Value Measurements at December 31, 2020 | |||||||||||||||||||||||
Quoted Prices in | Significant Other Observable Inputs | Significant Unobservable Inputs | Quoted Prices in | Significant Other Observable Inputs | Significant Unobservable Inputs | |||||||||||||||||||
Commodity derivatives - current liabilities | $ | 0 | $ | (183,850 | ) | $ | 0 | $ | - | $ | (602,760 | ) | $ | - | ||||||||||
Total | $ | 0 | $ | (183,850 | ) | $ | 0 | $ | - | $ | (602,760 | ) | $ | - |
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 Other current assets at September 30, 20202021 and Accounts payable, accrued expenses and other current liabilities at December 31, 2019.2020. 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, oil, natural gas and natural gas liquids revenue receivable, accounts payable and accrued expenses, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.
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. Periodically,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. The Partnership settled 3 derivative contracts during the first quarter of 2020, and in
In accordance with the Letteramended Simmons Loan Agreement discussed in Note 4. Debt, the Partnership iswas 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 31, 2020 until the next borrowing base redetermination date (first quarter of 2021).through February 2021. In August 2020,July 2021, the Partnership establishedbegan its risk management program required under the BF Loan Agreement (see Note 4. Debt) by entering into costless collar derivative contracts for future oil and natural gas produced by the Sanish Field Assets during the period from August 2020 through February 2021. All derivative instruments are recorded onJuly 2021 to September 2023. The Partnership did not pay or receive a premium related to the Partnership’s balance sheet as assets or liabilities measured at fair value.costless collars into which it entered to remain compliant with each loan agreement, and the contracts will be settled monthly.
As of September 30, 2020,2021, the Partnership’s derivative instruments with its counterparty were in a gain position; therefore,loss position. The Partnership has recognized a current assettotal liability of approximately $66,000,$2.3 million, of which approximates its fair value,$1.1 million has been recognizedrecorded as a derivative assetcurrent in Other current assetsDerivative liability and $1.2 million has been recorded as Derivative liability – noncurrent on the Partnership’s consolidated balance sheet as of September 30, 2020. As of December 31, 2019, the2021. The Partnership’s derivative instruments were in a loss position; therefore,position as of December 31, 2020; a current liability of approximately $0.2$0.6 million which approximates fair value, was recognized in Accounts payable, accrued expenses and other current liabilitiesas Derivative Liability on the Partnership’s consolidated balance sheet.sheet as of December 31, 2020. These current and noncurrent derivative liabilities as of September 31, 2021 and December 31, 2020 approximate fair value.
The Partnership determined 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 performed 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 considered that the counterparty is of substantial credit quality and had 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 Partnership hasdid not designateddesignate its derivative instruments as hedges for accounting purposes and hasdid not enteredenter 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’s contracts that expired during the third quarter of 2021 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 following table presents settlementsthe settlement gain (loss) of matured derivative instruments and non-cash mark-to-market gains on open derivative instruments(losses) for the periods presented.
Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||
Settlement gain (loss) on matured derivatives | $ | - | $ | 28,000 | $ | (1,182,420 | ) | $ | 285,040 | |||||||
Gain (loss) on mark-to-market of derivatives, net | (2,230,604 | ) | 66,299 | (1,627,844 | ) | 250,149 | ||||||||||
Gain (loss) on derivatives, net | $ | (2,230,604 | ) | $ | 94,299 | $ | (2,810,264 | ) | $ | 535,189 |
Settlements on matured derivatives belowabove reflect realized gains or 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)(non-cash, unrealized) gains belowor 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.
Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||
Settlements on matured derivatives | $ | 28,000 | $ | 0 | $ | 285,040 | $ | 0 | ||||||||
Gain on mark-to-market of derivatives | 66,299 | 498,790 | 250,149 | 498,790 | ||||||||||||
Gain on derivatives | $ | 94,299 | $ | 498,790 | $ | 535,189 | $ | 498,790 |
The Partnership generally uses costless collartable below summarizes the Partnership’s outstanding derivative contracts which establish floor(costless collars – purchased put options and ceiling priceswritten call options) on the Partnership’s future anticipatedoil and natural gas production. The Partnership did not pay or receive a premium related to the costless collars, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of September 30, 2020.
Settlement Period | Basis | Product | Volume | Floor / Ceiling Prices ($) | Fair Value of Asset / (Liability) at | |||||||
10/2020 - 02/2021 | NYMEX | Oil (bbls) | 75,000 | 37.50 / 44.50 | $ | 24,000 | ||||||
10/2020 - 02/2021 | NYMEX | Oil (bbls) | 75,000 | 38.00 / 44.25 | $ | 28,350 | ||||||
10/2020 - 02/2021 | NYMEX | Oil (bbls) | 75,000 | 38.00 / 44.00 | $ | 22,500 | ||||||
10/2020 - 02/2021 | NYMEX | Oil (bbls) | 48,000 | 38.00 / 44.50 | $ | 22,320 | ||||||
10/2020 - 02/2021 | Henry Hub | Gas (MMBtu) | 320,000 | 2.50 / 3.05 | $ | (30,871 | ) | |||||
$ | 66,299 |
Settlement Period | Basis | Product | Volume | Weighted Average | |||||
10/2021 - 12/2021 | NYMEX | Oil (bbls) | 93,000 | 50.00 / 83.50 | |||||
01/2022 - 12/2022 | NYMEX | Oil (bbls) | 332,000 | 50.00 / 76.17 | |||||
01/2023 - 09/2023 | NYMEX | Oil (bbls) | 224,000 | 50.00 / 69.72 | |||||
11/2021 - 12/2021 | Henry Hub | Gas (MMbtu) | 80,000 | 2.00 / 7.00 | |||||
01/2022 - 12/2022 | Henry Hub | Gas (MMbtu) | 390,000 | 2.00 / 6.04 | |||||
01/2023 - 09/2023 | Henry Hub | Gas (MMbtu) | 273,000 | 2.00 / 4.43 |
The Partnership’s outstanding derivative instruments are covered by an International Swap Dealers Association Master AgreementAgreements (“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 counterpartyits 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’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 offeringsoffering 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%). |
In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to recent market volatility caused by the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. The Partnership will accumulateaccumulates 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 defined above. As of September 30, 2020,2021, the unpaid Payout Accrual totaled $0.828493$2.228493 per common unit, or approximately $16$42 million. As discussed in Note 4. Debt, and pursuant to the Letter Agreement, the Partnership is not permittedmust meet certain conditions under the BF Loan Agreement before distributions to pay distributions without lender approval.limited partners may resume.
For the nine months ended September 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million. 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.
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, including approving the loan discussed below.
As described in Note 4. Debt, in July 2020, the Partnership entered into a loan agreement with GKDML, which provided for a $15 million unsecured, one-year Term Loan. GKDML is owned and managed by Messrs. Knight and McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A., which has substantially the same terms as the Term Loan and is personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and will not receive any consideration for providing the Term Loan or the guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimburse GKDML for all costs of its loan with Bank of America.transactions.
For the three and nine months ended September 30, 2020,2021, approximately $101,000$29,000 and $291,000$91,000 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, 2020,2021, approximately $101,000$29,000 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, 2019,2020, approximately $88,000$101,000 and $236,000$291,000 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 Mr. Knight, Mr. McKenney, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Messrs. Knight and 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 givesgave ER12 access to the Partnership’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The cost sharing agreement reduced these accounting and asset management costs to the Partnership, as these shared day-to-day costs arewere split evenly between the two partnerships and any direct third-party costs are paid by the party receiving the services.partnerships. The shared costs arewere based on actual costs incurred with no mark-up or profit to the Partnership. The agreement may be terminated at any timeAny other direct third-party costs were paid by eitherthe party upon 60 days written notice.
The Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate ofreceiving the General Partner. For the three and six months ended June 30, 2020 and 2019, the Partnership paid $25,611 and $51,222 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.services. For the three and nine months ended September 30, 2020, approximately $64,000 and $204,000, respectively, of expenses subject to the cost-sharingcost sharing agreement were paidincurred by the PartnershipER12 and have been reimbursed to the Partnership. In October 2020, the cost sharing agreement was terminated by ER12, effective December 31, 2020.
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 is 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 ER12. At September 30, 2020, the approximately $64,000 duePartnership. 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 from ER12 is included inprior 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 current assets inexpenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the consolidated balance sheets.Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the three and nine months ended September 30, 2019,2021, approximately $65,000$129,000 and $200,000,$420,000, respectively, of costs and expenses subject to the cost sharing agreementASA were paidreimbursed by the Partnership to the Administrator.
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 have been reimburseddoes not apply to the Partnership. The Administrator is owned by ER12.entities that are controlled by Messrs. Keating and Mallick.
Note 10. Subsequent Events
InDuring October 2020, ER12 provided 60-day written noticeand November 2021, the Partnership utilized cash available from operations to make principal payments on the BF Credit Facility of $7 million. The effect of these principal payments reduced the outstanding balance on the BF Credit Facility to $27 million. Because the Partnership’s outstanding balance is now at or below 50% of its current borrowing base and the Partnership is in compliance with its debt covenants under the BF Loan Agreement, the Partnership has met the conditions required by the Lender to resume payment of distributions to its limited partners.
Subsequent to the Partnership meeting the required conditions set forth by the Lender in the BF Loan Agreement, the General Partner approved the resumption of ER12’s intentiondistributions to terminatelimited partners for the cost sharing agreement betweenmonth of November 2021. On November 24, 2021, the Partnership and ER12. The cost sharing agreement will terminate on December 31, 2020.pay approximately $1 million, or $0.051781 per outstanding common unit, in distributions to its holders of common units.
Item 2. Management’sManagement’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 easing of COVID-19 and the return to pre-existing conditions following the ultimate recovery therefrom; |
● | 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, 2019, those described under Part II. Item 1A. Risk Factors included herein this Form 10-Q2020 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; |
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● | 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, 2019.2020.
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, 2020,2021, the Partnership owned an approximate 25% non-operated working interest in 243264 producing wells, an estimated approximate 18%20% non-operated working interest in 2114 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 twoone of the largest producers in the basin.basin, operates substantially all of the Sanish Field Assets.
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.
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.
DuringSince the beginning of 2019, and the first quarter of 2020, the Partnership has elected to participate in the drilling and completion of 4357 new wells in the Sanish field. Twenty-two (22)Forty-three (43) of these 4357 wells have been completed and were producing at September 30, 2020;2021; the Partnership has an approximate non-operated working interest of 23%21% in these 2243 wells. The Partnership has an estimated approximate non-operated working interest of 18%20% in the remaining 218 wells that are in-process as of September 30, 2020.2021. The Partnership has an estimated approximate non-operated working interest of 20% in six wells that had not commenced drilling as of September 30, 2021. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 4357 wells is approximately $63$75 million, of which approximately $42$56 million was incurred as of September 30, 2020. Due to the factors described below in “Current Price Environment,” Whiting suspended its Sanish field drilling program during the second quarter of 2020.2021. See additional detail in “Oil and Natural Gas Properties” below.
Drilling Program, Oil Demand, Liquidity and Going Concern Considerations
In conjunction with the Whiting drilling program described above, the Partnership had incurred approximately $42 million in capital expenditures through September 30, 2020, which was primarily funded by availability under the Partnership’s $40 million revolving credit facility (“Credit Facility”, described in “Financing” below). However, the Partnership used all availability under its Credit Facility by March 31, 2020, and as of June 30, 2020, the Partnership had approximately $20 million in accrued operating and capital expenditures due to Whiting. New production from completed wells was expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage. Subsequent to the Partnership’s election to participate in Whiting’s drilling program, several factors, described in “Current Price Environment” below, have had and are anticipated to have an adverse impact on the Partnership’s business and its financial condition. Due to these severe negative impacts to the global oil and gas industry, Whiting declared bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas on April 1, 2020, then subsequently suspended its Sanish field drilling program during the second quarter of 2020.
In July 2020, the Partnership entered into a loan agreement for a one year, $15 million term loan (“Affiliate Loan”) that matures on July 21, 2021 (see “Financing” below). The Partnership used proceeds from the Affiliate Loan plus cash on hand to pay the Partnership’s accrued operating and capital expenditures due to Whiting, which totaled approximately $19 million at the time of payment. In addition to the Affiliate Loan, the Partnership entered into a letter agreement (“Letter Agreement”) with its lender group for its Credit Facility. The Letter Agreement, among other items, waived the non-compliance of certain covenants under the Credit Facility; however, the Letter Agreement changed the maturity date of the Credit Facility from September 30, 2022 to July 31, 2021. In October 2020, the Partnership made a principal payment on the Affiliate Loan of $5 million; therefore, the Partnership’s outstanding debt obligations at the date of filing of this Form 10-Q total $50 million and mature within one year of the filing of this Form 10-Q.
The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) the Partnership’s ability to comply with its obligations under its loan agreements; (ii) refinancing its existing debt and/or securing additional capital; (iii) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (iv) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Refinancing its existing debt or securing additional capital may not be available on favorable terms to the Partnership, if it is available at all. There also can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will return to pre-COVID-19 levels, or that the Partnership will be able to meet its operational obligations. If the Partnership is unable to refinance or repay its debt obligations or is unable to meet its operational obligations, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy these obligations, which create the substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued.
Current Price Environment
Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Historically, worldwideworld-wide oil and natural gas prices and markets have been subject to significant change and volatility and willmay continue to be in the future. Since first being reportedGlobal macroeconomic factors contributing to uncertainty within the industry include real or perceived geopolitical risks in December 2019, COVID-19 spread worldwide, forcing governments aroundoil-producing regions of the world, to take drastic measures to haltparticularly the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closureMiddle East; forecasted levels of businesses in many industries, creating extreme volatility in capital markets and the global economy. Becauseeconomic growth combined with forecasted global supply; supply levels of COVID-19’s impact to the global economy, demand for fossil fuels substantially declined during the first quarter of 2020, and demand remained depressed during the second quarter of 2020. Although prices for oil and natural gas stabilizeddue to exploration and development activities in June 2020the United States; environmental and throughoutclimate change regulation; actions taken by the third quarterOrganization of 2020, prices remain below pre-COVID-19 levelsthe Petroleum Exporting Countries (“OPEC”); and are not anticipated to return to pre-COVID-19 levels during 2020.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. In addition to the outbreak of COVID-19, during the first quarter of 2020, Saudi Arabia and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020. Russia did not participate in production cuts coordinated by the Organization of the Petroleum Exporting Countries (“OPEC”), which2020 that ultimately led to Saudi Arabia lowering crude oil prices and both countries substantially increasing daily output of crude oil. The increase in Saudi and Russian oil output along with sustained production by other global producers, including the United States, has stressed the oil and gas industry’s capacity to store excess oil and gas. Despite Saudi Arabia, Russia, the United States and other OPEC members reaching an agreement in April 2020 to cut daily production, congested supply chain channels and excess crude oil and natural gas inventory are expected to weighand congested supply chain channels, which weighed negatively on commodity prices while demand remains low during COVID-19.was low. Demand for oil and natural gas began to return in the fourth quarter of 2020 as government-mandated COVID-19 restrictions eased. The increased demand and production restraint by domestic and foreign operators in 2021 have contributed to higher commodity prices, with oil prices averaging over $70 per barrel for the third quarter of 2021 and topping $80 per barrel in October 2021.
These factors led to oil prices falling to 20-year lows in April 2020, when the average daily NYMEX futures closing prices for the month was $16.70. In response to lower commodity prices and reduced demand, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs, and implemented other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. While operators have since returned significant inventory of existing wells to production, the nature and timing of drilling new wells remains uncertain. 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. As a result, sustained lowerIf commodity prices havesignificantly drop, such as the decline in the second quarter of 2020, and will continue to impact the amount of capitalremain low, the Partnership haswill 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, despite the addition of new wells discussed above, 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, 20202021 and 2019.2020.
Three Months Ended September 30, | Percent | Nine Months Ended September 30, | Percent | Three Months Ended September 30, | Percent | Nine Months Ended September 30, | Percent | |||||||||||||||||||||||||||||||||||||||||
2020 | 2019 | 2020 | 2019 | 2021 | 2020 | Change | 2021 | 2020 | Change | |||||||||||||||||||||||||||||||||||||||
Average market closing prices (1) | ||||||||||||||||||||||||||||||||||||||||||||||||
Oil (per Bbl) | $ | 40.91 | $ | 56.44 | -27.5 | % | $ | 38.22 | $ | 57.01 | -33.0 | % | $ | 70.52 | $ | 40.91 | 72.4 | % | $ | 65.04 | $ | 38.22 | 70.2 | % | ||||||||||||||||||||||||
Natural gas (per Mcf) | $ | 2.00 | $ | 2.38 | -16.0 | % | $ | 1.87 | $ | 2.62 | -28.6 | % | $ | 4.35 | $ | 2.00 | 117.5 | % | $ | 3.61 | $ | 1.87 | 93.0 | % |
(1) | Based on average NYMEX futures closing prices (oil) and NYMEX/Henry Hub spot prices (natural gas) |
Results of Operations
In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly 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 is a summary oftable summarizes the results from operations, including production, of the Partnership’s non-operated working interest for the three and nine months ended September 30, 2021 and 2020. The effect of the outbreak of COVID-19 during the first and second quarters of 2020 and 2019.had a significant negative impact to the Partnership’s results from operations; as a result, the periods presented in the table below may not be directly comparable.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||||||
2020 | Percent of Revenue | 2019 | Percent of Revenue | Percent | 2020 | Percent of Revenue | 2019 | Percent of Revenue | Percent | |||||||||||||||||||||||||||||||
Total revenues | $ | 9,650,268 | 100.0 | % | $ | 7,339,109 | 100.0 | % | 31.5 | % | $ | 25,506,320 | 100.0 | % | $ | 26,748,113 | 100.0 | % | -4.6 | % | ||||||||||||||||||||
Production expenses | 2,825,472 | 29.3 | % | 2,228,933 | 30.4 | % | 26.8 | % | 6,997,839 | 27.4 | % | 7,977,046 | 29.8 | % | -12.3 | % | ||||||||||||||||||||||||
Production taxes | 777,012 | 8.1 | % | 558,288 | 7.6 | % | 39.2 | % | 2,185,903 | 8.6 | % | 2,132,056 | 8.0 | % | 2.5 | % | ||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion | 6,112,621 | 63.3 | % | 2,767,479 | 37.7 | % | 120.9 | % | 16,575,336 | 65.0 | % | 9,403,364 | 35.2 | % | 76.3 | % | ||||||||||||||||||||||||
General, administration and other expense | 379,569 | 3.9 | % | 281,308 | 3.8 | % | 34.9 | % | 1,300,003 | 5.1 | % | 1,043,293 | 3.9 | % | 24.6 | % | ||||||||||||||||||||||||
Production (BOE): | ||||||||||||||||||||||||||||||||||||||||
Oil | 245,522 | 134,533 | 82.5 | % | 760,284 | 457,259 | 66.3 | % | ||||||||||||||||||||||||||||||||
Natural gas | 52,789 | 34,343 | 53.7 | % | 123,978 | 116,857 | 6.1 | % | ||||||||||||||||||||||||||||||||
Natural gas liquids | 44,573 | 24,807 | 79.7 | % | 112,797 | 99,726 | 13.1 | % | ||||||||||||||||||||||||||||||||
Total | 342,884 | 193,683 | 77.0 | % | 997,059 | 673,842 | 48.0 | % | ||||||||||||||||||||||||||||||||
Average sales price per unit: | ||||||||||||||||||||||||||||||||||||||||
Oil (per Bbl) | $ | 33.35 | $ | 49.43 | -32.5 | % | $ | 29.48 | $ | 49.45 | -40.4 | % | ||||||||||||||||||||||||||||
Natural gas (per Mcf) | 2.01 | 2.08 | -3.4 | % | 1.87 | 2.95 | -36.6 | % | ||||||||||||||||||||||||||||||||
Natural gas liquids (per Bbl) | 18.53 | 10.49 | 76.6 | % | 15.08 | 20.75 | -27.3 | % | ||||||||||||||||||||||||||||||||
Combined (per BOE) | 28.14 | 37.89 | -25.7 | % | 25.58 | 39.69 | -35.6 | % | ||||||||||||||||||||||||||||||||
Average unit cost per BOE: | ||||||||||||||||||||||||||||||||||||||||
Production expenses | 8.24 | 11.51 | -28.4 | % | 7.02 | 11.84 | -40.7 | % | ||||||||||||||||||||||||||||||||
Production taxes | 2.27 | 2.88 | -21.4 | % | 2.19 | 3.16 | -30.7 | % | ||||||||||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion | 17.83 | 14.29 | 24.8 | % | 16.62 | 13.95 | 19.1 | % | ||||||||||||||||||||||||||||||||
Capital expenditures | $ | 416,882 | $ | 5,957,663 | $ | 18,564,273 | $ | 7,808,174 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||
2021 | Percent of Revenue | 2020 | Percent of Revenue | Percent | 2021 | Percent of Revenue | 2020 | Percent of Revenue | Percent | |||||||||||||||||||||||||||
Total revenues | $ | 20,992,705 | 100.0 | % | $ | 9,650,268 | 100.0 | % | 117.5 | % | $ | 48,476,254 | 100.0 | % | $ | 25,506,320 | 100.0 | % | 90.1 | % | ||||||||||||||||
Production expenses | 2,747,487 | 13.1 | % | 2,825,472 | 29.3 | % | -2.8 | % | 8,270,708 | 17.1 | % | 6,997,839 | 27.4 | % | 18.2 | % | ||||||||||||||||||||
Production taxes | 1,653,661 | 7.9 | % | 777,012 | 8.1 | % | 112.8 | % | 3,749,060 | 7.7 | % | 2,185,903 | 8.6 | % | 71.5 | % | ||||||||||||||||||||
Depreciation, depletion, amortization and accretion | 6,547,607 | 31.2 | % | 6,112,621 | 63.3 | % | 7.1 | % | 16,387,823 | 33.8 | % | 16,575,336 | 65.0 | % | -1.1 | % | ||||||||||||||||||||
General and administrative expenses | 325,168 | 1.5 | % | 379,569 | 3.9 | % | -14.3 | % | 1,172,298 | 2.4 | % | 1,300,003 | 5.1 | % | -9.8 | % | ||||||||||||||||||||
Production (BOE): | ||||||||||||||||||||||||||||||||||||
Oil | 276,320 | 245,522 | 12.5 | % | 677,815 | 760,284 | -10.8 | % | ||||||||||||||||||||||||||||
Natural gas | 46,350 | 52,789 | -12.2 | % | 137,014 | 123,978 | 10.5 | % | ||||||||||||||||||||||||||||
Natural gas liquids | 39,520 | 44,573 | -11.3 | % | 115,327 | 112,797 | 2.2 | % | ||||||||||||||||||||||||||||
Total | 362,190 | 342,884 | 5.6 | % | 930,156 | 997,059 | -6.7 | % | ||||||||||||||||||||||||||||
Average sales price per unit: | ||||||||||||||||||||||||||||||||||||
Oil (per Bbl) | $ | 64.74 | $ | 33.35 | 94.1 | % | $ | 59.54 | $ | 29.48 | 102.0 | % | ||||||||||||||||||||||||
Natural gas (per Mcf) | 4.56 | 2.01 | 126.9 | % | 4.40 | 1.87 | 135.3 | % | ||||||||||||||||||||||||||||
Natural gas liquids (per Bbl) | 46.44 | 18.53 | 150.6 | % | 39.06 | 15.08 | 159.0 | % | ||||||||||||||||||||||||||||
Combined (per BOE) | 57.96 | 28.14 | 105.9 | % | 52.12 | 25.58 | 103.8 | % | ||||||||||||||||||||||||||||
Average unit cost per BOE: | ||||||||||||||||||||||||||||||||||||
Production expenses | 7.59 | 8.24 | -7.9 | % | 8.89 | 7.02 | 26.6 | % | ||||||||||||||||||||||||||||
Production taxes | 4.57 | 2.27 | 101.5 | % | 4.03 | 2.19 | 84.0 | % | ||||||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion | 18.08 | 17.83 | 1.4 | % | 17.62 | 16.62 | 6.0 | % | ||||||||||||||||||||||||||||
Capital expenditures | $ | 4,374,019 | $ | 416,882 | $ | 17,698,191 | $ | 18,564,273 |
Oil, Natural Gasnatural gas and NGL Revenuesrevenues
For the three months ended September 30, 2021, revenues from oil, natural gas and NGL sales were $21.0 million. Revenues for the sale of crude oil were $17.9 million, which resulted in a realized price of $64.74 per barrel. Revenues for the sale of natural gas were $1.3 million, which resulted in a realized price of $4.56 per Mcf. Revenues for the sale of NGLs were $1.8 million, which resulted in a realized price of $46.44 per BOE of sold production. For the three months ended September 30, 2020, revenues for oil, natural gas and NGL sales were $9.7 million. Revenues for the sale of crude oil were $8.2 million, which resulted in a realized price of $33.35 per barrel. Revenues for the sale of natural gas were $0.6 million, which resulted in a realized price of $2.01 per Mcf. Revenues for the sale of NGLs were $0.8 million, which resulted in a realized price of $18.53 per BOE of sold production.
For the threenine months ended September 30, 2019,2021, revenues forfrom oil, natural gas and NGL sales were $7.3$48.5 million. Revenues for the sale of crude oil were $6.6$40.4 million, which resulted in a realized price of $49.43$59.54 per barrel. Revenues for the sale of natural gas were $0.4$3.6 million, which resulted in a realized price of $2.08$4.40 per Mcf. Revenues for the sale of NGLs were $0.3$4.5 million, which resulted in a realized price of $10.49$39.06 per BOE of sold production.
For the nine months ended September 30, 2020, revenues for oil, natural gas and NGL sales were $25.5 million. Revenues for the sale of crude oil were $22.4 million, which resulted in a realized price of $29.48 per barrel. Revenues for the sale of natural gas were $1.4 million, which resulted in a realized price of $1.87 per Mcf. Revenues for the sale of NGLs were $1.7 million, which resulted in a realized price of $15.08 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.
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. Due to produced oil from the Sanish field exceeding demand and reduced storage capacity available at refineries, the Partnership’s oil price differential increased during the second quarter of 2020. However, as market supply and demand imbalances began to stabilize in July 2020, the Partnership’s oil price differential returned to historical levels during the third quarter of 2020. In July 2020, a federal judge ruled that two significant pipelines that transport oil and natural gas from North Dakota fields, including the Sanish field, must suspend operations due to environmental review and disputes over right to use land owned by Native Americans (this ruling was later stayed on appeal and the case remains active in court). If use of the region pipelines is suspended at a future date, the Partnership anticipates its differential would increase. Realized sales prices for natural gas and NGLs were also negatively impacted in 2020 due to processing and transportation constraints, discussed above in “Current Price Environment” and below in “Production Expenses”, as product leaves the Sanish field.
The Partnership’s results for the three and nine months ended September 30, 20202021 were negativelypositively impacted by the Partnership’s realized sales prices for oil, natural gas and NGLs, which decreased in line with market commodity prices described in “Current Price Environment” above, in comparison to the same periods of 2019. However, the Partnership’ssignificant increase in sold production volumes for the three and nine months ended September 30, 2020 helped offset the negative impact of lower realized sales prices. The Partnership has completed 22 new wells since the fourth quarter of 2019, which led to increases in the Partnership’s sold production volumesmarket prices of oil, natural gas and NGLs when compared to the same periods of 2020. Specifically, the Partnership realized increases exceeding average market gas and NGL prices in February 2021 as a result of the severe winter weather storms that resulted in power outages in Texas and other southern states. In addition, the Partnership’s realized sales price for oil have benefited from improved differentials (see below) during 2021 as the market imbalances and certain supply chain constraints that developed during the spring and summer of 2020 due to COVID-19 have eased.
The Partnership completed 22 new wells from the fourth quarter of 2019 (duringthrough the third quarter of 2019, production from some of the Partnership’s existing producing wells was temporarily suspended to allow for the commencement of drilling wells now complete on the Partnership’s acreage).2020. In addition, the Partnership’s operators did not curtail production or shut-in a significant number of producingturned an additional 21 new wells to sales during the second and third quarters of 2021. The timing of when these wells were completed have positively contributed to sold oil production during the three and nine months ended September 30, 2021 and 2020, as new wells often have high levels of production immediately following completion, then decline to more consistent levels. Further, the Partnership’s operators have improved the treatment and processing of extracted natural gas from the Sanish Field Assets, ultimately reducing the natural gas shrink and yielding higher gas and NGL volumes during the nine months ended September 30, 2021, in comparison to the same period of 2020. While the natural gas and NGL sales volumes for the three months ended September 30, 2021 lag behind sold production from natural gas and NGL in the same period of 2020, the Partnership anticipates the completion of the 21 wells discussed above, some of which were completed late in third quarter of 2020, so2021, along with improved operator efficiency will contribute to an increase in natural gas and NGL sales volumes in the Partnership has benefited from stable production throughout 2020.fourth quarter of 2021. Sold production for the Sanish Field Assets was approximately 3,7003,900 BOE per day and 3,6003,400 BOE per day for the three and nine months ended September 30, 2020, respectively, while sold2021, including approximately 4,600 BOE per day in September 2021. Sold production was approximately 2,1003,700 BOE and 2,500 BOE3,600 per day for the three and nine months ended September 30, 2019, respectively.2020.
If commodity prices fall from current levels and operators are unable to produce, process and sell oil and natural gas at economical prices, the operators in the Sanish field 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. If certain wells are shut-in, there can be no assurance regarding how they will produce if and when they are brought back on-line. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion of the Partnership’s investment in new wells in “Liquidity and Capital Resources” below.
Differentials
The Partnership has 21 wells currentlyrealized 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 various stagesmoving produced oil at the wellhead to a refinery and are based on the availability of drillingpipeline, rail and completion,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 timingBakken, oil price differentials were approximately 14% and 32% less during the three and nine months ended September 30, 2021 than those of completionthe same periods of these wells2020, 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, which is unknownanticipated to be issued in the fall of 2022. If use of the Dakota Access Pipeline or any other region pipelines is suspended at this time. Therefore,a future date, the Partnership will experience naturaldisruption of transporting the Partnership’s production declines until market conditions improve andout of North Dakota could negatively impact the 21 in-process wells are completed.Partnership’s realized sales prices, results of operations or cash flows.
Operating Costscosts and Expensesexpenses
Production Expensesexpenses
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 watersaltwater 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 treatmentmarketing of natural gas.
For the three months ended September 30, 20202021 and 2019,2020, production expenses were $2.8$2.7 million and $2.2$2.8 million, respectively, and production expenses per BOE of sold production were $8.24$7.59 and $11.51,$8.24, respectively. For the nine months ended September 30, 20202021 and 2019,2020, production expenses were $7.0$8.3 million and $8.0$7.0 million, respectively, and production expenses per BOE of sold production were $7.02$8.89 and $11.84,$7.02, respectively. Production expenses per BOE fordecreased in the three andmonths ended September 30, 2021, in comparison to the same period of 2020, primarily due to higher sold production volumes, which increases the production base over which fixed costs are spread. However, production expenses per BOE increased in the nine months ended September 30, 2020 were below the prior year expenses of2021, in comparison to the same periods per BOE primarily due toperiod of 2020, as a result of (i) an increase in sold production volumes along with fixed lease operating expenses; (ii) other operating cost-saving measures implemented by the Partnership’s operators while market commodity prices are depressed; and (iii)workover expenses as certain of the Partnership’s existing producing wells beingthat had been temporarily suspended for the development of new wells as noted above, or workover repairs.required additional rework prior to being returned 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 Taxestaxes
Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. ProductionTaxes on the sale of gas and NGL products are less than taxes forlevied on the three months ended September 30, 2020 and 2019 were $0.8 million (8%sale of revenue) and $0.6 million (8% of revenue), respectively. Production taxes for the nine months ended September 30, 2020 and 2019 were $2.2 million (9% of revenue) and $2.1 million (8% of revenue), respectively. Productionoil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLNGLs to total sales. Taxes onProduction taxes for the salethree months ended September 30, 2021 and 2020 were $1.7 million (8% of gasrevenue) and NGL products$0.8 million (8% of revenue), respectively. Production taxes for the nine months ended September 30, 2021 and 2020 were $3.7 million (8% of revenue) and $2.2 million (9% of revenue), respectively.
General and administrative expenses
General and administrative expenses for the three months ended September 30, 2021 and 2020 were $0.3 million and $0.4 million, respectively. General and administrative expenses for the nine months ended September 30, 2021 and 2020 were $1.2 million and $1.3 million, respectively. The principal components of general and administrative expense are less than taxes levied onaccounting, legal and consulting fees. The Partnership incurred higher legal fees to protect its rights under joint operating agreements with its operators in the salethree- and nine-month periods ended September 30, 2020, resulting in higher general and administrative expenses in 2020 compared to the same periods of oil.2021.
Depreciation, Depletion, Amortizationdepletion, amortization and Accretion (“accretion (“DD&A”&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, 2021 and 2020 and 2019 was $6.1$6.5 million and $2.8$6.1 million, and DD&A per BOE of sold production was $17.83$18.08 and $14.29,$17.83, respectively. DD&A for the nine months ended September 30, 2021 and 2020 and 2019 was $16.6$16.4 million and $9.4$16.6 million, and DD&A per BOE of sold production was $16.62$17.62 and $13.95,$16.62, respectively. The increase in DD&A expense per BOE of production is primarily due to the decrease of the Partnership’s estimated proved undeveloped reserves (“PUDs”) resulting from (i) changes to the Partnership’s future drilling schedule and (ii) investment in new wells during the fourth quarter of 2019 and first quarter of 2020.
General and Administrative Costs
General and administrative costs for the three months ended September 30, 2020 and 2019 were $0.4 million and $0.3 million, respectively. General and administrative costs for the nine months ended September 30, 2020 and 2019 were $1.3 million and $1.0 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees. The increase in general and administrative costs for the three- and nine-month periods ended September 30, 2020,2021, compared to the same periodsperiod of 2019,2020, is primarily due to higher legal fees incurred to protect the Partnership’s rights under joint operating agreements with its operators.continued investment in new wells and lower sold production volumes.
Gain (loss) on Derivativesderivatives, 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. The Partnership settled three derivative contracts during the first quarter of 2020, and in
In accordance with the Letteramended Simmons Loan Agreement discussed in “Financing” below, the Partnership iswas 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 31, 2020 until the next borrowing base redetermination date (first quarter of 2021).through February 2021. In August 2020,July 2021, the Partnership establishedbegan its risk management program required under the BF Loan Agreement (see “Financing” below) by entering into costless collar derivative contracts for future oil and natural gas produced by the Sanish Field Assets during the period from August 2020 through February 2021.
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.July 2021 to September 2023. The following table presents settlements of its matured derivative instruments and the non-cash, mark-to-market gaingains or losses recorded during the periods presented.
Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||
Settlements on matured derivatives | $ | 28,000 | $ | - | $ | 285,040 | $ | - | ||||||||
Gain on mark-to-market of derivatives | 66,299 | 498,790 | 250,149 | 498,790 | ||||||||||||
Gain on derivatives | $ | 94,299 | $ | 498,790 | $ | 535,189 | $ | 498,790 |
Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||
Settlement gain (loss) on matured derivatives | $ | - | $ | 28,000 | $ | (1,182,420 | ) | $ | 285,040 | |||||||
Gain (loss) on mark-to-market of derivatives, net | (2,230,604 | ) | 66,299 | (1,627,844 | ) | 250,149 | ||||||||||
Gain (loss) on derivatives, net | $ | (2,230,604 | ) | $ | 94,299 | $ | (2,810,264 | ) | $ | 535,189 |
The Partnership’s oil production contracts that expired during the third quarter of 2021 represented approximately 99,000 barrels of oil; however, these oil production contracts were settled at no cost or benefit to the Partnership, realized gains of approximately $28,000as the contract prices on the dates of settlement of matured derivativewere within the established floor and ceiling prices. The Partnership’s oil production contracts that expired during the threenine months ended September 30, 2020. Settlement gains are calculated2021 represented approximately 204,000 barrels of oil. The Partnership’s realized loss of approximately $1.2 million equated to an approximate loss of $5.80 per barrel of oil. The Partnership’s natural gas production contracts that expired during the three and nine months ended September 30, 2021 represented 120,000 MMBtu and 240,000 MMBtu of produced natural gas, respectively; however, these natural gas production contracts were settled at no cost or benefit to the Partnership, as the difference between the contract price on the date of settlement was within the established floor and the market settlement price. ceiling prices.
The Partnership’s oil production contracts that expired during the three months ended September 30, 2020 represented 122,000 barrels of oil; however, these oil 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 Partnership’s natural gas production contracts that expired during the three months ended September 30, 2020 represented 140,000 Mcf of produced natural gas, and settlement gains were $28,000, or $0.20 per Mcf.
The Partnership realized gains of approximately $285,000 on the settlement of matured derivative contracts during the nine months ended September 30, 2020. The Partnership’s oil production contracts that expired during the nine months ended September 30, 2020 represented 204,000 barrels of oil, and settlement gains were approximately $257,000, or $1.26 per barrel of oil. The Partnership’s natural gas production contracts that expired during the three and nine months ended September 30, 2020 represented 140,000 McfMMBtu of produced natural gas, and settlement gains were $28,000, or $0.20 per Mcf.MMBtu.
The mark-to-market (non-cash, unrealized) gains or losses recorded for the three-three and nine-month periodsnine months ended September 30, 20202021 and 20192020 represent the change in fair value of the Partnership’s derivative instruments held at period-end. These unrealizedUnrealized gains and losses do not represent actual settlements and noor payments were 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 | |||||||
10/ | NYMEX | Oil (bbls) |
| 93,000 |
|
| ||||||
| NYMEX |
| Oil (bbls) |
| 332,000 |
|
| |||||
| NYMEX |
| Oil (bbls) |
| 224,000 | 50.00 / 69.72 | ||||||
11/2021 - 12/2021 |
| Gas (MMbtu) | 80,000 | 2.00 / | ||||||||
| Henry Hub | Gas (MMbtu) |
| 390,000 |
|
|
| |||||
| Henry Hub | Gas (MMbtu) |
| 273,000 |
|
|
|
Interest Expense, Netexpense, net
Interest expense, net, for the three months ended September 30, 2021 and 2020 and 2019 was $0.5$0.4 million and $0.2$0.5 million, respectively. Interest expense, net, for the nine months ended September 30, 2021 and 2020 and 2019 was $1.4$1.5 million and $0.6$1.4 million, respectively. The primary componentscomponent of Interest expense, net, during the three- and nine-month periods ended September 30, 20202021 was interest expense on the Simmons Credit Facility, and the Affiliate Loan and the BF Credit Facility discussed below in “Financing.” The primary component of Interest expense, net, during the three- and nine-month periods ended September 30, 20192020 was interest expense on the Simmons Credit Facility. The addition of the Affiliate Loan along with increased borrowings and an increase to the interest rate of the Partnership’s existing Credit Facility under the Letter Agreement, discussed below in “Financing”, resulted in an increase to the Partnership’s interest expense during the three and nine months ended September 30, 2020, as compared to the same periods of 2019.
Supplemental Non-GAAP Measure
The Partnership uses “Adjusted EBITDAX”, defined as earnings (loss) 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 nine months ended September 30, 20202021 and 2019.2020.
Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | Three Months Ended | Three Months Ended | Nine Months Ended | Nine Months Ended | |||||||||||||||||||||||||
Net income (loss) | $ | (879,896 | ) | $ | 1,794,044 | $ | (2,387,990 | ) | $ | 6,093,081 | $ | 7,042,790 | $ | (879,896 | ) | $ | 14,633,169 | $ | (2,387,990 | ) | ||||||||||||
Interest expense, net | 529,789 | 207,847 | 1,370,418 | 598,063 | 445,388 | 529,789 | 1,452,932 | 1,370,418 | ||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion | 6,112,621 | 2,767,479 | 16,575,336 | 9,403,364 | 6,547,607 | 6,112,621 | 16,387,823 | 16,575,336 | ||||||||||||||||||||||||
Exploration expenses | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Non-cash gain on mark-to-market of derivatives | (66,299 | ) | (498,790 | ) | (250,149 | ) | (498,790 | ) | ||||||||||||||||||||||||
Non-cash (gain) loss on mark-to-market of derivatives, net | 2,230,604 | (66,299 | ) | 1,627,844 | (250,149 | ) | ||||||||||||||||||||||||||
Adjusted EBITDAX | $ | 5,696,215 | $ | 4,270,580 | $ | 15,307,615 | $ | 15,595,718 | $ | 16,266,389 | $ | 5,696,215 | $ | 34,101,768 | $ | 15,307,615 |
Liquidity and Capital Resources
Historically, the Partnership’s principal sources of liquidity werehave been cash on hand, the cash flow generated from the Sanish Field Assets, and availability under the Partnership’s revolving credit facility, if any. As of September 30, 2020, theThe Partnership had borrowed $40generated approximately $24.0 million under its revolving credit facility, which represents all availability under the revolving credit facility. In July 2020, the Partnership utilized the proceedsin cash flow from an affiliate term loan (described below in “Financing”) and cash on hand to repay amounts outstanding to Whiting of approximately $19 million (upon payment of the outstanding amounts, Whiting released all liens it had asserted against the Sanish Field Assets). At September 30, 2020, the Partnership held unrestricted cash and cash equivalents of $5.3 million andoperating activities for the nine months ended September 30, 2020,2021. In May 2021, the Partnership generated $15.1 million in cash flowssuccessfully refinanced its existing Simmons Bank credit facility (see “Financing” below) and used the initial closing proceeds from operations. As discussed in “Drilling Program, Oil Demand, Liquidity, and Going Concern Considerations” above, there are no assurances that cashthe refinancing with BancFirst to fully repay the outstanding balance on hand andthe Simmons credit facility. Using excess cash flow from operations will be sufficient to continue to fundrealized from May 2021 through October 2021, the Partnership’s operations and repay its indebtedness, describedPartnership has made principal payments on the BancFirst credit facility of approximately $13 million. As of the date of the filing of this Form 10-Q, the Partnership had approximately $27 million in “Financing” below.available credit under the BancFirst credit facility.
FinancingThe Partnership’s principal payments on the BancFirst credit facility described above reduced the outstanding balance of the credit facility at or below 50% of the Partnership’s current borrowing base. In addition, the Partnership is in compliance with its applicable debt covenants as of the date of the filing of this Form 10-Q. As a result, the Partnership has met the conditions required by its lending party to resume elective payment of distributions to its limited partners. As described in “Subsequent Events”, the General Partner approved the payment of a distribution to holders of the Partnership’s common units 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 making monthly principal payments to ensure 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.
Revolving Credit Facility
At September 30, 2020,The Partnership anticipates its cash on-hand, cash flow from operations and availability under its refinanced 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. Although the Partnership anticipates its cash on-hand, cash flow from operations and credit facility availability to be adequate to fund its cash requirements, if market prices for oil and natural gas decline and/or production from Partnership wells is not replenished through the completion of new well investments, the Partnership’s outstanding balancecash flow from operations may decline. This could have a significant impact on the Credit Facility was $40 million, andPartnership’s available cash on-hand, the interest rate forPartnership’s ability to participate in future drilling programs as proposed by the Credit Facility was 4.25%.
On July 21, 2020,operators of the Partnership entered into the Letter Agreement withSanish Field Assets and/or to fund any future distributions to its lending group that amended and modified the Credit Facility. The modifications include, among other items, the following:limited partners.
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In addition to the modification of certain terms of theRevolving Credit Facility, the Letter Agreement waived the defaults by the Partnership under the Amended Loan Agreement that existed prior to signing the Letter Agreement, including not meeting the current ratio covenant as of March 31, 2020, the Partnership not filing its first quarter financial statements within 60 days of March 31, 2020 and the non-payment by the Partnership of amounts due to Whiting. The Letter Agreement also waived the Partnership’s calculation of the current ratio covenant at June 30, 2020. The Letter Agreement also allowed for the Affiliate Loan discussed below and payments under the Affiliate Loan.Facilities
In considerationNovember 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 $40 million, subject to borrowing base restrictions, that was to mature on July 31, 2021. The Simmons Credit Facility had an interest rate of 4.25% and outstanding borrowings of $40 million as of May 13, 2021.
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 modifications, amendmentslenders (the “Lender”), which provides for a revolving credit facility (“BF Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $60 million, subject to borrowing base restrictions. The Partnership paid an origination fee of 0.50% of the Maximum Credit Amount, or $300,000, and waivers described aboveis subject to an additional fee of 0.25% on any incremental increase to the Amendedborrowing base. Total capitalized loan costs were approximately $0.4 million and are being amortized over the life of the BF Credit Facility. The Partnership also is required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2024.
At closing, the Partnership borrowed approximately $40 million. The proceeds were used to pay the $40 million outstanding balance and accrued interest on the Simmons Credit Facility described above. Any further advances under the BF Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the BF Loan Agreement, the LetterPartnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.
Under the BF Loan Agreement, provides for an amendment feethe initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which is initially stipulated to Lenderbe $1 million. Therefore, as of $40,000, of which $15,000 was paid on September 30, 20202021, the borrowing base was $56 million. The borrowing base and $25,000Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. The Lender did not make any adjustments to the Partnership’s borrowing base or the Monthly Commitment Reduction provision based on its September 1, 2021 redetermination analysis. The Lender is due December 31, 2020.also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period. Outstanding borrowings under the BF Credit Facility cannot exceed the lesser of the borrowing base or the Maximum Credit Amount at any time. The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.00%.
Also under the BF Loan Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production. 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 less than 50% of the lesser of the (i) Maximum Credit Amount or (ii) 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 lesser of the (i) Maximum Credit Amount or (ii) 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 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:
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● | A minimum ratio of current assets to current liabilities of 1.00 to 1.00 | |
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The BF Loan Agreement restricts the Partnership’s ability to pay limited partner distributions until the outstanding balance of the BF Credit Facility is equal to or less than 50% of the lesser of the (i) Maximum Credit Amount or (ii) current borrowing base, at which point 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.
At September 30, 2021, the outstanding balance on the BF Credit Facility was approximately $34 million, and the interest rate was 4.00%. The Partnership was in compliance with its applicable covenants at September 30, 2020. If the Partnership is not in compliance with its covenants in future periods, it may not be able to obtain waivers and the outstanding balance under the Credit Facility may become due on demand at that time. See additional information in “Note 4. Debt” in Part I, Item 1 of this Form 10-Q.2021.
Term Loan from Affiliate
On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which providesprovided for an unsecured, one-year term loan (“Term Loan” or “Affiliate Loan”) in the amount of $15 million. GKDML is owned and managed by Glade M. Knight and David S. McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. The Term Loan bearswas repaid in full during March 2021, and the Partnership did not incur a penalty for prepayment. The Term Loan bore interest at a variable rate based on LIBOR plus a margin of 2.00%, with a LIBOR floor of 0%. Interest iswas payable monthly. The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. At September 30, 2020, the outstanding balance on the Term Loan was $15 million, the interest rate for the Term Loan was approximately 2.2% and the Partnership was in compliance of all applicable covenants.
To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A. on July 21, 2020 (“GKDML Loan”). The GKDML Loan haswas also repaid in March 2021, had substantially the same terms as the Term Loan and iswas personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and willdid not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimbursereimbursed GKDML for all costs of the GKDML Loan. The Term Loan may be prepaid at any time with no penalty and in any amount, but any amounts repaid may not be reborrowed. The Partnership anticipates utilizing cash from operations to reduce outstanding balances under the Term Loan.
Partners’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 recent market volatility caused by the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. As discussed in “Financing” above, the Partnership must meet certain conditions under the BF Loan Agreement before distributions to limited partners may resume. The Partnership will accumulate 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.occurs, as defined above. As of September 30, 2020,2021, the unpaid Payout Accrual totaled $0.828493$2.228493 per common unit, or approximately $16$42 million. As discussed in “Financing” above and pursuant to the Letter Agreement, the Partnership is not permitted to pay distributions without lender approval.
For the nine months ended September 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million. 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.
Oil and Natural Gas Properties
The Partnership incurred approximately $18.6$17.7 million and $7.8$18.6 million in capital expenditures for the nine months ended September 30, 20202021 and 2019,2020, respectively.
DuringSince the second halfbeginning of 2019, and the first quarter of 2020, the Partnership has elected to participate in the drilling and completion of 4357 new wells at an estimated cost toin the PartnershipSanish field. Forty-three (43) of approximately $63 million. Through September 30, 2020, the Partnership has incurred approximately $42 million in capital expenditures related to the 43 wells. As of September 30, 2020, 22 of these 57 wells have been completed and 21 were producing at September 30, 2021; the Partnership has an approximate non-operated working interest of 21% in process. these 43 wells. The Partnership has an estimated approximate non-operated working interest of 20% in 8 wells that are in-process as of September 30, 2021. The Partnership has an estimated approximate non-operated working interest of 20% in six wells that had not commenced drilling as of September 30, 2021. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 57 wells is approximately $75 million, of which approximately $56 million was incurred as of September 30, 2021.
The Partnership anticipates thatits operators to complete the remaining 21 in-process14 wells will remain in drilled, but uncompleted (“DUC”) status throughduring the end of 2020, and the timing fornext three to nine months; however, completion of these DUCthe wells is dependent upon an increasenot in commodity pricing.the Partnership’s control. The Partnership estimates it will incur approximately $1the approximate $15 to $220 million in additional capital expenditures duringto complete the remaining 14 wells will be incurred over the fourth quarter of 2020. However,2021 and the first half of 2022 based on the best available information regarding current capital investment plans from its operators. Many factors described in “Current Price Environment” along withoutside the uncertainty of when Whiting will resume its drilling program after emerging from bankruptcy protection in September 2020Partnership’s control make it difficult to predict the amount and timing of capital expenditures for the remainder of 20202021 and into the first half of 2021,2022, and estimated capital expenditures could be significantly different from amounts actually invested.
As discussed in “Drilling Program, Oil Demand, Liquidity and Going Concern Considerations”, the Partnership’s liquidity is currently dependent upon cash from operations and if it is not able to generate sufficient cash to fund capital expenditures, it may not be able to complete is obligations under the currently suspended drilling program or participate fully in future wells. Based upon information from its operators, development during through the first half of 2020 and a reduction in commodity prices, the Partnership decreased its proved undeveloped reserves (“PUD”) from 11,980 MBOE at December 31, 2019 to 2,737 MBOE at June 30, 2020. Approximately 63% of this decrease in PUD reserve volumes was the result of a change in the planned timing of the drilling and completion of PUD reserve locations outside of the SEC five-year window, while the remaining 37% of the decrease resulted from PUD conversion to proved developed reserves and lower oil and natural gas prices. The Partnership did not make any further drill schedule adjustments during the third quarter of 2020.
In addition to the approximate $21 million in estimated capital expenditures to be incurred for the drilling and completion of the 43 wells in which the Partnership has elected to participate (upon resumption of the drilling program), the Partnership anticipates that it may be obligated to invest an additional $25 to $30 million in capital expenditures from 20212022 through 20242026 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 BF Credit Facility. If the Partnership is not able to generate sufficient cash from operation or there is no availability under the BF 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
InDuring October 2020, ER12 provided 60-day written noticeand November 2021, the Partnership utilized cash available from operations to make principal payments on the BF Credit Facility of $7 million. The effect of these principal payments reduced the outstanding balance on the BF Credit Facility to $27 million. Because the Partnership’s outstanding balance is now at or below 50% of its current borrowing base and the Partnership is in compliance with its debt covenants under the BF Loan Agreement, the Partnership has met the conditions required by the Lender to resume payment of distributions to its limited partners.
Subsequent to the Partnership meeting the required conditions set forth by the Lender in the BF Loan Agreement, the General Partner approved the resumption of ER12’s intentiondistributions to terminatelimited partners for the cost sharing agreement betweenmonth of November 2021. On November 24, 2021, the Partnership and ER12. The cost sharing agreement will terminate on December 31, 2020.pay approximately $1 million, or $0.051781 per outstanding common unit, in distributions to its holders of common units.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership hashad variable interest rates on its Simmons Credit Facility and Affiliate Loan that arewere subject to market changes in interest rates. In addition, the Partnership’s BF Credit Facility is subject to a variable interest rate. Information regarding the Partnership’s Simmons Credit Facility, andthe Affiliate Loan and the BancFirst 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 September 30, 20202021 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, 20202021 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
TheFor a discussion of the Partnership’s potential risks and uncertainties, are discussed in Item 1A. Risk Factorssee the section titled “Risk Factors” in the Partnership’s 2020 Annual Report on Form 10-K for the year ended December 31, 2019. The information below updates, and should be read in conjunction with, the risk factors and information disclosed in the Partnership’s 2019 Form 10-K. Except as presented below, thereThere have been no material changes fromto the risk factors described in our 2019 Form 10-K.
The Partnership may not be able to obtain waivers of future covenant violations under its Credit Facility.
In July 2020, the Partnership received a waiver from its lender group that suspended the calculation of the current ratio covenant until September 30, 2020 and waived certain other defaults under the Credit Facility. If the Partnership violates covenants under the Credit Facilitypreviously disclosed in the future and is unable to obtain waivers, the lenders will have the right to accelerate all of the outstanding indebtedness under the Credit Facility. If the lenders were to accelerate all of the obligations outstanding under the Credit Facility, the Partnership would be required to pay approximately $40 million (as of September 30, 2020) to the lenders. Additionally, the Partnership would be in default under its Affiliate Loan of $15 million.
The current widespread outbreak of COVID-19 has significantly adversely impacted and disrupted, and is expected to continue to adversely impact and disrupt, the Partnership’s business and the industry in which the Partnership operates.
In December 2019, China reported an outbreak of COVID-19 in its Wuhan province. On March 11, 2020 the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States declared a national emergency with respect to COVID-19. COVID-19 has spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures include significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy.
COVID-19’s impact to the global economy, in particular the oil and gas industry, has been unprecedented, as reduced demand for fossil fuels has resulted in a significant decline in commodity prices during March and April 2020. The Partnership experienced a decline in anticipated revenue during March 2020 and through the third quarter of 2020 due to commodity price declines, and the Partnership expects demand for oil and gas as well as commodity prices to be low for the remainder of 2020, which will negatively impact the Partnership’s business during the fourth quarter of 2020 and potentially beyond. The Partnership cannot give any assurance as to when demand will return to more normal levels or if commodity prices will increase.
The COVID-19 pandemic and related restrictions aimed at mitigating its spread have caused the General Partner to modify certain of the Partnership’s business practices, including limiting employee travel, encouraging work-from-home practices and other social distancing measures. Such measures may cause disruptions to the Partnership’s business and operational plans, which may include shortages of employees, contractors and subcontractors. There is no certainty that these or any other future measures will be sufficient to mitigate the risks posed by the disease, including the risk of infection of key employees, and the Partnership’s ability to perform certain functions could be impaired by these new business practices. For example, the Partnership’s reliance on technology has necessarily increased due to the General Partner’s encouragement of remote communications and other work-from-home practices, which could make the Partnership more vulnerable to cyber-attacks.
The spread of COVID-19 has caused severe disruptions in the global economy, specifically the oil and gas industry, and could potentially create widespread business continuity issues of an as yet unknown magnitude and duration.
COVID-19 has caused severe economic, market and other disruptions worldwide. In many respects, it is too early to quantify the long-term ramifications of COVID-19 on the global economy as well as oil and gas industry, the Partnership’s operators and the Partnership’s business. Further, it is currently not possible to predict how long the COVID-19 pandemic will last or the time that it will take for economic activity to return to prior levels. As a result, the Partnership cannot provide an estimate of the overall impact of COVID-19 on its business or when, or if, the Partnership and its operators will be able to resume normal, pre-COVID-19 operations. Nevertheless, sustained lower oil and gas prices and reduced demand resulting from COVID-19 present material uncertainty and risk with respect to the Partnership’s business, financial performance and condition, operating results and cash flows. In addition, low oil and natural gas prices may cause the Partnership’s undrilled wellsites to become uneconomic to develop.
Crude oil prices declined significantly in the first quarter of 2020 and into the second quarter of 2020. If oil prices remain at current levels or decline further for a prolonged period, the Partnership’s operations and financial condition may be materially and adversely affected.
In the first quarter of 2020 and through the beginning of the second quarter, crude oil prices fell sharply and dramatically, due in part to significantly decreased demand as a result of the COVID-19 pandemic and the significantly increased supply of crude oil as a result of a price war between Saudi Arabia and Russia. In April 2020, Saudi Arabia, Russia, the United States and other members of OPEC agreed to certain production cuts; however, these cuts are not expected to be enough to offset near-term demand loss attributable to the COVID-19 pandemic. Prices for WTI crude oil were over $60 per barrel at the beginning of 2020 before declining significantly through March and further declined as prices fell below $20 per barrel by the end of April 2020. Oil prices have stabilized around $40 per barrel since June 2020; however, if crude oil prices remain at current levels or further decline for a prolonged period, the Partnership’s operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to the Partnership’s properties may be materially and adversely affected.
As domestic demand for crude oil has declined substantially due to COVID-19, the General Partner cannot ensure that there will be a physical market for the Partnership’s production at economic prices until markets stabilize.
As a result of low commodity prices, the operators of the Partnership’s wells have and may curtail a portion of the Partnership’s estimated crude oil production and may store rather than sell additional crude oil production in the near future. Additionally, an excess supply of oil could lead to further curtailments by those operators. While the Partnership believes that the shutting-in of such production will not impact the productivity of such wells when reopened, there is no assurance the Partnership will not have a degradation in well performance upon returning those wells to production. The storing or shutting in of a portion of the Partnership’s production can also result in increased costs under midstream and other contracts. Any of the foregoing could result in an adverse impact on the Partnership’s revenues, financial position and cash flows.
The Partnership has substantial liquidity needs and may not be able to obtain sufficient liquidity to continue as a going concern.
In addition to the cash requirements necessary to fund ongoing operations, including scheduled debt service obligations and payment of incurred capital expenditures and general and administrative costs, the Partnership may incur significant professional fees and other costs to obtain alternative financing. There can be no assurance that cash on hand and cash flows from operations in a period of sustained lower commodity prices will be sufficient to continue to fund the Partnership’s operations, including debt service, for any significant period of time.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 | |
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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 | ||
32.2 | ||
101 | The following materials from Energy 11, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, | |
104 | The cover page from the Partnership’s Quarterly Report on Form 10-Q for the quarter ended September 30, | |
*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. | |||
By: Energy 11 G.P., LLC, its General Partner | |||
By: | /s/ Glade M. Knight | ||
Glade M. Knight | |||
Chief Executive Officer (Principal Executive Officer) | |||
By: | /s/ David S. McKenney | ||
David S. McKenney | |||
Chief Financial Officer (Principal Financial and Accounting Officer) | |||
Date: November |