See accompanying notes to condensed consolidated financial statements.
Note 1. Organization and Nature of Operations
Nature of Operations
Mid-Con Energy Partners, LP (“we,” “our,” “us,” the “Partnership” or the “Company”) is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition and development of producing oil and natural gas properties in North America, with a focus on enhanced oil recovery (“EOR”). Our limited partner units (“common units”) are listed under the symbol “MCEP” on the NASDAQ.
On June 5, 2020, the Partnership announced the completion of the strategic recapitalization transactions (the “Recapitalization Transactions”), that resulted in significant changes to our capital structure and governance, strengthened our balance sheet, created alignment across all unitholders, reduced costs and streamlined operations and created immediate and sustainable value for all unitholders. In connection with these Recapitalization Transactions, the limited partnership agreement of the Partnership was amended and restated, and the Partnership entered into a Management Services Agreement (“MSA”) with Contango Resources, Inc. (“Contango Resources”) effective as of July 1, 2020. Under the MSA, Contango Resources will provide management and administrative services and serve as the operator of the Partnership’s assets for a flat fee arrangement of $4.0 million annually, plus a maximum $2.0 million termination fee, which is expected to generate pro forma annual cash savings of approximately $6.5 million compared with 2019.
Basis of Presentation
Our unaudited condensed consolidated financial statements are prepared pursuant to the rules and regulations of the SEC. These financial statements have not been audited by our independent registered public accounting firm, except that the condensed consolidated balance sheet at December 31, 2019, is derived from the audited financial statements. Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted in this Form 10-Q. We believe that the presentations and disclosures made are adequate to make the information not misleading.
The unaudited condensed consolidated financial statements include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full year. These interim financial statements should be read in conjunction with our Annual Report. All intercompany transactions and account balances have been eliminated.
Liquidity and Going Concern
These unaudited condensed consolidated financial statements have been prepared on a going concern basis, which contemplates the continuity of normal business activities and the realization of assets and settlement of liabilities in the normal course of business. At March 31, 2020, the Partnership was not in compliance with the leverage ratio covenant of our credit agreement. On June 4, 2020, Amendment 15 to the credit agreement was executed, decreasing the borrowing base of the revolving credit facility from $95.0 million to $64.0 million, establishing a repayment schedule for the borrowing base deficiency and waiving the March 31, 2020, leverage ratio noncompliance. See Note 7 in this section for additional information on Amendment 15 to the credit agreement. At June 30, 2020, the Partnership was in compliance with the financial covenants required by the credit agreement. Our ability to continue as a going concern is dependent on the re-negotiation of our revolving credit agreement that matures May 1, 2021, or other measures such as the sale of assets or raising additional capital. There can be no assurance, however, that such discussions will result in a refinancing of the credit facility on acceptable terms, if at all, or provide any specific amount of additional liquidity. These factors raise substantial doubt over the Partnership’s ability to continue as a going concern for at least one year from the date that these financial statements are issued, and therefore, whether we will realize our assets and extinguish our liabilities in the normal course of business and at the amounts stated in the unaudited condensed consolidated financial statements. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty, nor do they include adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts and classifications of liabilities that might be necessary should the Partnership be unable to continue as a going concern.
10
Non-cash Investing and Supplemental Cash Flow Information
The following presents the non-cash investing and supplemental cash flow information for the periods presented:
|
|
Six Months Ended
June 30,
|
|
(in thousands)
|
|
2020
|
|
|
2019
|
|
Non-cash investing information
|
|
|
|
|
|
|
|
|
Conversion of preferred equity to common units
|
|
$
|
(36,708
|
)
|
|
$
|
—
|
|
Change in oil and natural gas properties - assets received in exchange
|
|
$
|
—
|
|
|
$
|
38,533
|
|
Change in oil and natural gas properties - accrued capital expenditures
|
|
$
|
(2,090
|
)
|
|
$
|
(74
|
)
|
Change in oil and natural gas properties - accrued acquisitions
|
|
$
|
360
|
|
|
$
|
(1,428
|
)
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
1,940
|
|
|
$
|
2,619
|
|
Reverse Unit Split
On April 9, 2020, the Partnership effected a 1-for-20 reverse common unit split. For presentation purposes, the unaudited condensed consolidated financial statements and footnotes have been adjusted to reflect this reverse unit split as if it had occurred at the beginning of the periods presented.
Note 2. Acquisitions, Divestitures and Assets Held for Sale
Assets and liabilities assumed in acquisitions accounted for as business combinations are recorded in our unaudited condensed consolidated balance sheets at their estimated fair values as of the acquisition date using assumptions that represent Level 3 fair value measurement inputs. See Note 5 in this section for additional discussion of our fair value measurements.
Results of operations attributable to the acquisition subsequent to the closing are included in our unaudited condensed consolidated statements of operations. The operations and cash flows of divested properties are eliminated from our ongoing operations.
Strategic Transaction
In March 2019, we simultaneously closed the previously announced definitive agreements to sell substantially all of our oil and natural gas properties located in Texas for $60.0 million and to purchase certain oil and natural gas properties located in Osage, Grady and Caddo Counties in Oklahoma for an aggregate purchase price of $27.5 million, both agreements subject to customary purchase price adjustments. We received net proceeds of $32.5 million at the close of this strategic transaction (“Strategic Transaction”) of which $32.0 million was used to reduce borrowings outstanding under our revolving credit facility. The acquired properties were accounted for as an asset acquisition. A gain on the sale of oil and natural gas properties of $9.5 million was reported in the unaudited condensed consolidated statements of operations for the six months ended June 30, 2019.
The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited condensed consolidated statements of operations for the periods presented:
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
(in thousands)
|
|
2020
|
|
|
2019
|
|
|
2020
|
|
|
2019
|
|
Oil and natural gas sales
|
|
$
|
—
|
|
|
$
|
39
|
|
|
$
|
—
|
|
|
$
|
4,689
|
|
Expenses(1)
|
|
$
|
—
|
|
|
$
|
(4
|
)
|
|
$
|
—
|
|
|
$
|
3,370
|
|
(1) Expenses include lease operating expenses ("LOE"), production and ad valorem taxes, accretion and depletion.
|
|
Divestiture
On January 23, 2020, we closed the sale of land in Southern Oklahoma for a net cash settlement of $0.4 million. At December 31, 2019, the carrying value of $0.4 million was presented in “Assets held for sale” in our unaudited condensed consolidated balance sheets. No gain or loss on the transaction was recorded during the six months ended June 30, 2020.
11
Note 3. Equity Awards
We have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and directors of our general partner and its former affiliates, including Mid-Con Energy Operating, LLC (“Mid-Con Energy Operating”) and ME3 Oilfield Service, LLC (“ME3 Oilfield Service”), who performed services for us. The Long-Term Incentive Program allows for the award of unit options, unit appreciation rights, unrestricted units, restricted units, phantom units, distribution equivalent rights granted with phantom units and other types of awards. The Long-Term Incentive Program is administered by the voting members of our general partner, and approved by the Board of Directors of our general partner (the “Board”). If an employee terminates employment prior to the restriction lapse date, the awarded units are forfeited and canceled and are no longer considered issued and outstanding.
The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at June 30, 2020:
|
|
Number of
Common
Units
|
|
Approved and authorized awards
|
|
|
175,700
|
|
Unrestricted units granted
|
|
|
(69,160
|
)
|
Restricted units granted, net of forfeitures
|
|
|
(19,971
|
)
|
Equity-settled phantom units granted, net of forfeitures
|
|
|
(72,251
|
)
|
Awards available for future grant
|
|
|
14,318
|
|
We recognized $0.2 million and $0.3 million of total equity-based compensation expense for the three and six months ended June 30, 2020, respectively. We recognized $0.1 million and $0.4 million of total equity-based compensation expense for the three and six months ended June 30, 2019. These costs are reported as a component of general and administrative expenses (“G&A”) in our unaudited condensed consolidated statements of operations.
Unrestricted Unit Awards
During the six months ended June 30, 2020, we granted 1,633 unrestricted units with an average grant date fair value of $5.20, as adjusted for the reverse unit split. During the six months ended June 30, 2019, we granted 2,500 unrestricted units with an average grant date fair value of $20.80 per unit, as adjusted for the reverse unit split.
Equity-Settled Phantom Unit Awards
Equity-settled phantom units vest over a period of two or three years. During the six months ended June 30, 2020, we did not grant any equity-settled phantom units. During the six months ended June 30, 2019, we granted 25,500 equity-settled phantom units with a two-year vesting period and 3,150 equity-settled phantom units with a three-year vesting period, as adjusted for the reverse split.
A summary of our equity-settled phantom unit awards for the six months ended June 30, 2020, is presented below:
|
|
Number of
Equity-Settled
Phantom Units
|
|
|
Average Grant Date
Fair Value per Unit
|
|
Outstanding at December 31, 2019
|
|
|
28,550
|
|
|
$
|
25.00
|
|
Units vested
|
|
|
(26,267
|
)
|
|
|
15.73
|
|
Units forfeited
|
|
|
(2,283
|
)
|
|
|
23.24
|
|
Outstanding at June 30, 2020
|
|
|
-
|
|
|
$
|
-
|
|
Note 4. Derivative Financial Instruments
Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivative contracts (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent or as
12
required by our lenders. We account for our commodity derivative contracts at fair value. See Note 5 in this section for a description of our fair value measurements.
We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of our commodity derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash gains or losses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net amounts paid or received on monthly settlements, proceeds from or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, we present the fair value of commodity derivative contracts on a net basis.
At June 30, 2020, our commodity derivative contracts were in a net asset position with a fair value of $12.2 million, whereas at December 31, 2019, our commodity derivative contracts were in a net liability position with a fair value of $1.2 million. All of our commodity derivative contracts are with major financial institutions that are also lenders under our revolving credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our commodity derivative contracts under lower commodity prices and we could incur a loss. As of June 30, 2020, all of our counterparties have performed pursuant to the terms of their commodity derivative contracts.
The following tables summarize the gross fair value by the appropriate balance sheet classification, even when the derivative financial instruments are subject to netting arrangements and qualify for net presentation, in our unaudited condensed consolidated balance sheets at June 30, 2020, and December 31, 2019:
(in thousands)
|
|
Gross
Amounts
Recognized
|
|
|
Gross Amounts
Offset in the
Unaudited
Condensed
Consolidated
Balance Sheets
|
|
|
Net Amounts
Presented in
the Unaudited
Condensed
Consolidated
Balance Sheets
|
|
June 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current asset
|
|
$
|
9,032
|
|
|
$
|
(108
|
)
|
|
$
|
8,924
|
|
Derivative financial instruments - long-term asset
|
|
|
3,497
|
|
|
|
(177
|
)
|
|
$
|
3,320
|
|
Total
|
|
|
12,529
|
|
|
|
(285
|
)
|
|
|
12,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current liability
|
|
|
(108
|
)
|
|
|
108
|
|
|
|
—
|
|
Derivative financial instruments - long-term liability
|
|
|
(177
|
)
|
|
|
177
|
|
|
|
—
|
|
Total
|
|
|
(285
|
)
|
|
|
285
|
|
|
|
—
|
|
Net asset
|
|
$
|
12,244
|
|
|
$
|
—
|
|
|
$
|
12,244
|
|
13
(in thousands)
|
|
Gross
Amounts
Recognized
|
|
|
Gross Amounts
Offset in the
Unaudited
Condensed
Consolidated
Balance Sheets
|
|
|
Net Amounts
Presented in
the Unaudited
Condensed
Consolidated
Balance Sheets
|
|
December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - long-term asset
|
|
$
|
1,635
|
|
|
$
|
(905
|
)
|
|
$
|
730
|
|
Total
|
|
|
1,635
|
|
|
|
(905
|
)
|
|
|
730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current liability
|
|
|
(1,944
|
)
|
|
|
—
|
|
|
|
(1,944
|
)
|
Derivative financial instruments - long-term liability
|
|
|
(905
|
)
|
|
|
905
|
|
|
|
—
|
|
Total
|
|
|
(2,849
|
)
|
|
|
905
|
|
|
|
(1,944
|
)
|
Net liability
|
|
$
|
(1,214
|
)
|
|
$
|
—
|
|
|
$
|
(1,214
|
)
|
The following table presents the impact of derivative financial instruments and their location within the unaudited condensed consolidated statements of operations:
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
(in thousands)
|
|
2020
|
|
|
2019
|
|
|
2020
|
|
|
2019
|
|
Net settlements on matured derivatives
|
|
$
|
5,201
|
|
|
$
|
(729
|
)
|
|
$
|
6,984
|
|
|
$
|
(586
|
)
|
Net change in fair value of derivatives
|
|
|
(9,712
|
)
|
|
|
4,125
|
|
|
|
13,457
|
|
|
|
(8,216
|
)
|
Total (loss) gain on derivatives, net
|
|
$
|
(4,511
|
)
|
|
$
|
3,396
|
|
|
$
|
20,441
|
|
|
$
|
(8,802
|
)
|
At June 30, 2020, and December 31, 2019, our commodity derivative contracts had maturities at various dates through December 2021 and were comprised of commodity price swap and collar contracts. At June 30, 2020, we had the following oil derivatives net positions:
Period Covered
|
|
Weighted Average Fixed Price
|
|
|
Weighted Average Floor Price
|
|
|
Weighted Average Ceiling Price
|
|
|
Total Bbls
Hedged/day
|
|
|
Index
|
Swaps - 2020
|
|
$
|
55.98
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
1,798
|
|
|
NYMEX-WTI
|
Swaps - 2021
|
|
$
|
55.78
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
672
|
|
|
NYMEX-WTI
|
Collars - 2021
|
|
$
|
—
|
|
|
$
|
52.00
|
|
|
$
|
58.80
|
|
|
|
672
|
|
|
NYMEX-WTI
|
At December 31, 2019, we had the following oil derivatives net positions:
Period Covered
|
|
Weighted Average Fixed Price
|
|
|
Weighted Average Floor Price
|
|
|
Weighted Average Ceiling Price
|
|
|
Total Bbls
Hedged/day
|
|
|
Index
|
Swaps - 2020
|
|
$
|
55.81
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
1,931
|
|
|
NYMEX-WTI
|
Swaps - 2021
|
|
$
|
55.78
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
672
|
|
|
NYMEX-WTI
|
Collars - 2021
|
|
$
|
—
|
|
|
$
|
52.00
|
|
|
$
|
58.80
|
|
|
|
672
|
|
|
NYMEX-WTI
|
Note 5. Fair Value Disclosures
Fair Value of Financial Instruments
The carrying amounts reported in our unaudited condensed consolidated balance sheets for cash, accounts receivable and accounts payable approximate their fair values. The carrying amount of debt under our revolving credit facility approximates fair value because the revolving credit facility’s variable interest rate resets frequently and approximates current market rates available to us. We account for our commodity derivative contracts at fair value as discussed in “Assets and Liabilities Measured at Fair Value on a Recurring Basis” below.
14
Fair Value Measurements
Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy that is intended to increase consistency and comparability in fair value measurements and related disclosures. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded in the balance sheet are categorized based on the inputs to the valuation technique as follows:
Level 1 - Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. We consider active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an on-going basis.
Level 2 - Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Level 2 instruments primarily include swap, call, put and collar contracts.
Level 3 - Financial assets and liabilities for which values are based on prices or valuation approaches that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. We had no transfers in or out of Levels 1, 2 or 3 for the three and six months ended June 30, 2020, and for the year ended December 31, 2019.
Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no material changes in valuation approach or related inputs for the three and six months ended June 30, 2020, and for the year ended December 31, 2019.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
We account for commodity derivative contracts and their corresponding deferred premiums at fair value on a recurring basis utilizing certain pricing models. Inputs to the pricing models include publicly available prices from a compilation of data gathered from third parties and brokers. We validate the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Any deferred premiums associated with our commodity derivative contracts are categorized as Level 3, as we utilize a net present value calculation to determine the valuation. See Note 4 in this section for a summary of our derivative financial instruments.
The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as of June 30, 2020, and December 31, 2019:
(in thousands)
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Fair Value
|
|
June 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - asset
|
|
$
|
—
|
|
|
$
|
12,529
|
|
|
$
|
—
|
|
|
$
|
12,529
|
|
Derivative financial instruments - liability
|
|
$
|
—
|
|
|
$
|
285
|
|
|
$
|
—
|
|
|
$
|
285
|
|
December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - asset
|
|
$
|
—
|
|
|
$
|
1,635
|
|
|
$
|
—
|
|
|
$
|
1,635
|
|
Derivative financial instruments - liability
|
|
$
|
—
|
|
|
$
|
2,849
|
|
|
$
|
—
|
|
|
$
|
2,849
|
|
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Asset Retirement Obligations
We estimate the fair value of our asset retirement obligations (“ARO”) based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for ARO, amounts
15
and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 6 in this section for a summary of changes in ARO.
Acquisitions
The estimated fair values of proved oil and natural gas properties acquired in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates at the acquisition date. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and natural gas properties acquired is deemed to use Level 3 inputs. See Note 2 in this section for further discussion of our acquisitions.
Reserves
We calculate the estimated fair values of reserves and properties using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of reserves, future operating and developmental costs, future commodity prices, a market-based weighted average cost of capital rate and the rate at which future cash flows are discounted to estimate present value. We discount future values by a per annum rate of 10% because we believe this amount approximates our long-term cost of capital and accordingly, is well aligned with our internal business decisions. The underlying commodity prices embedded in our estimated cash flows begin with Level 1 NYMEX-WTI forward curve pricing, less Level 3 assumptions that include location, pricing adjustments and quality differentials.
Impairment
The need to test oil and natural gas assets for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the estimated undiscounted future net cash flows, an impairment expense is recognized for the difference between the estimated fair value and the carrying value of the assets. Due to the unprecedented decline in oil prices, we recorded impairment expense of $1.2 million and $19.5 million for the three and six months ended June 30, 2020, respectively. We recorded impairment expense of $0.2 million for the three and six months ended June 30, 2019.
Note 6. Asset Retirement Obligations
We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or successfully drilling a well and determine our ARO by calculating the present value of estimated cash flow related to the estimated future liability. Determining the removal and future restoration obligation requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of future ARO on an annual basis, or more frequently, if an event or circumstances occur that would impact our assumptions. To the extent future revisions to these assumptions impact the present value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. The liability is accreted each period toward its future value and is recorded in our unaudited condensed consolidated statements of operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets based on proved developed reserves. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.
16
As of June 30, 2020, and December 31, 2019, our ARO were reported as asset retirement obligations in our unaudited condensed consolidated balance sheets. Changes in our ARO for the periods indicated are presented in the following table:
(in thousands)
|
|
Six Months Ended
June 30, 2020
|
|
|
Year Ended
December 31, 2019
|
|
Asset retirement obligations - beginning of period
|
|
$
|
30,265
|
|
|
$
|
26,001
|
|
Liabilities incurred for new wells and interest
|
|
|
637
|
|
|
|
8,840
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
(6
|
)
|
|
|
(24
|
)
|
Liabilities removed upon sale of wells
|
|
|
—
|
|
|
|
(5,795
|
)
|
Revision of estimates
|
|
|
—
|
|
|
|
(353
|
)
|
Accretion expense
|
|
|
838
|
|
|
|
1,596
|
|
Asset retirement obligations - end of period
|
|
$
|
31,734
|
|
|
$
|
30,265
|
|
Note 7. Debt
We had outstanding borrowings under our revolving credit facility of $73.3 million and $68.0 million at June 30, 2020, and December 31, 2019, respectively. Our current revolving credit facility matures in May 2021. Borrowings under the facility are secured by liens on not less than 90% of the value of our proved reserves. At March 31, 2020, we were not in compliance with our leverage ratio covenant, which was waived in Amendment 15 to the credit agreement, executed June 4, 2020. At June 30, 2020, we were in compliance with the financial covenants required by our credit agreement.
The borrowing base of our revolving credit facility is collectively determined by our lenders based on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other variables. The borrowing base is subject to scheduled redeterminations in the spring and fall of each year with an additional redetermination, either at our request or at the request of the lenders, during the period between each scheduled borrowing base redetermination. An additional borrowing base redetermination may be made at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract. Our spring 2020 redetermination was finalized in June 2020. The next regularly scheduled semi-annual redetermination is expected to be completed in the fall of 2020.
At June 30, 2020, borrowings under the revolving credit facility bore interest at a floating rate based on, at our election, the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50% and the one month adjusted London Interbank Offered Rate (“LIBOR”) plus 1.0%, all of which are subject to a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or the applicable LIBOR plus a margin that varies from 2.75% to 3.75% per annum according to the borrowing base usage. For the three months ended June 30, 2020, the average effective rate was 5.49%. Any unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Letters of credit are subject to a letter of credit fee that varies from 2.75% to 3.75% according to usage.
We may use borrowings under the revolving credit facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. The revolving credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, and restrictions on certain transactions and payments, including distributions, and requires us to maintain hedges covering projected production. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the credit agreement, together with accrued interest, could be declared immediately due and payable.
On March 28, 2019, in conjunction with closing the Strategic Transaction and serving as our spring redetermination, Amendment 13 to the credit agreement was executed, decreasing our borrowing base to $110.0 million. The amendment also required that the leverage ratio be calculated on a building, period-annualized basis, beginning with the second quarter of 2019. See Note 2 in this section for further discussion of the Strategic Transaction.
17
On December 6, 2019, Amendment 14 to the credit agreement was executed, decreasing the borrowing base of the Partnership’s revolving credit facility to $95.0 million. The amendment also extended the maturity date of the revolving credit facility to May 1, 2021, and provided for a benchmark rate replacement to address the transition of LIBOR in 2021. Under the terms of the amendment, the Partnership is required to have a Consolidated Funded Indebtedness to Consolidated EBITDAX of less than 3.0 to 1.0 to make any borrowings above the borrowing cap of $85.0 million, and must maintain a maximum Leverage Ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX that does not exceed:
|
•
|
4.0 to 1.0 for the quarter ending December 31, 2019,
|
|
•
|
3.75 to 1.0 for the quarter ending March 31, 2020, and
|
|
•
|
3.5 to 1.0 for the quarter ending June 30, 2020, and thereafter.
|
Amendment 15 to the credit agreement, effective June 1, 2020, among other changes decreased the borrowing base from $95.0 million to $64.0 million and established a monthly repayment schedule beginning June 1, 2020, through November 1, 2020, for the $11.0 borrowing base deficiency; permitted the Recapitalization Transactions; introduced anti-cash hoarding provisions and restrictive covenants on capital and general and administrative spending; provided for all loans to bear payment-in-kind interest, capitalized on a quarterly basis; excluded certain assumed liabilities from the Current Ratio calculation for the quarters ending June 30, 2020, September 30, 2020 and December 31, 2020; and required the Partnership’s Leverage Ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX not to exceed:
|
•
|
5.75 to 1.0 for the quarter ending June 30, 2020,
|
|
•
|
5.00 to 1.0 for the quarter ending September 30, 2020;
|
|
•
|
4.50 to 1.0 for the quarter ending December 31, 2020; and
|
|
•
|
4.25 to 1.0 for the quarter ending March 31, 2021, and thereafter.
|
Note 8. Commitments and Contingencies
Services Agreement
As of June 30, 2020, we were a party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provided certain services to us including management, administrative and operational services. We reimbursed Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurred in its performance under the services agreement. These expenses included, among other things, salary, bonus, incentive compensation and other amounts paid to persons who performed services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. These expenses were included in G&A in our unaudited condensed consolidated statements of operations.
The Partnership entered into a master services agreement with Contango Resources on June 4, 2020, as part of the Recapitalization Transaction. Under the agreement, Contango Resources will provide management and administrative services and serve as the operator of the Partnership’s assets for a flat fee arrangement of $4.0 million annually, plus a maximum $2.0 million termination fee, effective July 1, 2020.
Employment Agreements
As part of the Restructuring Transactions, the general partner terminated the employment agreements of Charles R. Olmstead and Jeffrey R. Olmstead. Pursuant to the employment agreements, each employee served in his respective position with our general partner and had duties, responsibilities and authority as the Board specified from time to time, in roles consistent with such positions that were assigned to them. The agreements stipulated that if there was a change of control, termination of employment, with cause or without cause, or death of the executive certain payments would be made to the executive officer. No payments were made under the employment agreements.
Change in Control Severance Plan
On July 24, 2019, the Board adopted a Change in Control Severance Plan that provides severance benefits to certain key management employees of the former general partner and its affiliates. The Change in Control Severance Plan provides for the payment of cash compensation and certain other benefits to eligible employees in the event of a change in control and a qualifying termination of employment. The obligations under the Change in Control Severance Plan are generally based on the terminated employee’s cash compensation and position within the Partnership. Depending on the facts and circumstances associated with a potential change in control, the total payments made pursuant to the Change in Control Severance Plan could be material. At June 30, 2020, no liability has been recorded associated with the Change in Control Severance Plan. For a more detailed description of the Change in Control Severance Plan, please refer to our Current Report on Form 8-K filed with the SEC on July 26, 2019.
18
Legal
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us under the various environmental protection statutes to which we are subject.
Note 9. Equity
Common Units
At June 30, 2020, and December 31, 2019, the Partnership’s equity consisted of 14,311,522 and 1,541,215 common units, respectively, representing a 100% and 98.8% limited partnership interest in us, respectively.
Our Partnership Agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. As of June 30, 2020, cash distributions to our common units continued to be indefinitely suspended. Our credit agreement stipulates written consent from our lenders is required in order to reinstate common unit distributions. Management and the Board will continue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determining future distributions. The suspension of common unit cash distributions is designed to preserve liquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-term value for our unitholders. There is no assurance as to future cash distributions since they are dependent upon our projections for future earnings, cash flows, capital requirements, financial conditions and other factors.
Preferred Units
The Partnership had previously issued Class A and Class B Preferred Units (collectively, the “Preferred Units”). Per accounting guidance, we were required to allocate a portion of the proceeds from Preferred Units to a beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value was calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per-share value of our common units at the issuance date) and the proceeds attributed to the class of Preferred Units. The beneficial conversion feature was accreted using the effective yield method over the period from the closing date to the effective date of the holder’s conversion right.
The holders of our Preferred Units were entitled to certain rights that were senior to the rights of holders of common units, such as rights to distributions and rights upon liquidation of the Partnership. We paid holders of Preferred Units a cumulative, quarterly cash distribution on Preferred Units then outstanding at an annual rate of 8.0%, or in the event that the Partnership’s existing secured indebtedness prevented the payment of a cash distribution to all holders of the Preferred Units, in kind (additional Class A or Class B Preferred Units), at an annual rate of 10.0%. Such distributions were paid for each such quarter within 45 days after such quarter end, or as otherwise permitted to accumulate pursuant to the Partnership Agreement.
Each holder of Preferred Units had the right, prior to August 11, 2021, subject to certain conditions, to convert all or a portion of their Preferred Units into common units on a one-for-one basis, subject to adjustment for splits, subdivisions, combinations and reclassifications of the common units. Upon conversion of the Preferred Units, the Partnership would pay any distributions (to the extent accrued and unpaid as of the then most recent Preferred Units distribution date) on the converted units in cash, or in the event that the Partnership’s existing secured indebtedness prevents the payment of a cash distribution to all holders of the Preferred Units, in kind (additional Class A or Class B Preferred Units), at an annual rate of 10.0%.
As part of the Recapitalization Transactions on June 4, 2020, the holders of all of the Partnership’s Preferred Units converted their Preferred Units to common units at an average conversion price of $3.12 per Preferred Unit. The total of $0.8 million in accrued distributions for the first quarter 2020 were paid in kind and, along with the second quarter 2020 pro-rata distribution, included in the calculation of the conversion price to common units.
Class A Preferred Units
On August 11, 2016, we completed a private placement of 11,627,906 Class A Preferred Units for an aggregate offering price of $25.0 million. The Class A Preferred Units were issued at a price of $2.15 per Class A Preferred Unit. Proceeds from this issuance were used to fund an acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $24.6 million in connection with the issuance of these Class A Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class A Preferred Units ($18.6 million)
19
and the beneficial conversion feature ($6.0 million). Accretion of the beneficial conversion feature was $0.2 million and $0.5 million for the three and six months ended June 30, 2020, and $0.3 million and $0.6 million for the three and six months ended June 30, 2019. The registration statement registering resales of common units issued upon conversion of the Class A Preferred Units was declared effective by the SEC on June 14, 2017.
As the holders of all the Partnership’s Preferred Units received payment in kind for all accrued distributions as part of the previously announced Recapitalization Transaction, the Partnership did not accrue any distributions as of June 30, 2020. The following table summarizes cash distributions paid on our Class A Preferred Units during the six months ended June 30, 2020:
Date Paid
|
|
Period Covered
|
|
Distribution per
Unit
|
|
|
Total Distributions
(in thousands)
|
|
February 14, 2020
|
|
October 1, 2019 - December 31, 2019
|
|
$
|
0.0430
|
|
|
$
|
500
|
|
The following table summarizes cash distributions paid on our Class A Preferred Units during the six months ended June 30, 2019:
Date Paid
|
|
Period Covered
|
|
Distribution per
Unit
|
|
|
Total Distributions
(in thousands)
|
|
February 14, 2019
|
|
October 1, 2018 - December 31, 2018
|
|
$
|
0.0430
|
|
|
$
|
500
|
|
May 14, 2019
|
|
January 1, 2019 - March 31, 2019
|
|
$
|
0.0430
|
|
|
$
|
500
|
|
Class B Preferred Units
On January 31, 2018, we completed a private placement of 9,803,921 Class B Preferred Units for an aggregate offering price of $15.0 million. The Class B Preferred Units were issued at a price of $1.53 per Class B Preferred Unit. Proceeds from this issuance were used to fund the acquisition of certain oil and natural gas properties located in Campbell and Converse Counties, Wyoming, and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $14.9 million in connection with the issuance of these Class B Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class B Preferred Units ($14.2 million) and the beneficial conversion feature ($0.7 million). Accretion of the beneficial conversion feature was $0.03 million and $0.1 million for the three and six months ended June 30, 2020, and $0.1 million for the three and six months ended June 30, 2019. The registration statement registering resales of common units issued upon conversion of the Class B Preferred Units was declared effective by the SEC on May 25, 2018.
As the holders of all the Partnership’s Preferred Units received payment in kind for all accrued distributions as part of the previously announced Recapitalization Transaction, the Partnership did not accrue any distributions as of June 30, 2020. The following table summarizes cash distributions paid on our Class B Preferred Units during the six months ended June 30, 2020:
Date Paid
|
|
Period Covered
|
|
Distribution per
Unit
|
|
|
Total Distributions
(in thousands)
|
|
February 14, 2020
|
|
October 1, 2019 - December 31, 2019
|
|
$
|
0.0306
|
|
|
$
|
300
|
|
The following table summarizes cash distributions paid on our Class B Preferred Units during the six months ended June 30, 2019:
Date Paid
|
|
Period Covered
|
|
Distribution per
Unit
|
|
|
Total Distributions
(in thousands)
|
|
February 14, 2019
|
|
October 1, 2018 - December 31, 2018
|
|
$
|
0.0306
|
|
|
$
|
300
|
|
May 14, 2019
|
|
January 1, 2019 - March 31, 2019
|
|
$
|
0.0306
|
|
|
$
|
300
|
|
Allocation of Net Income or Loss
Net income or loss was allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss was allocated to the limited partner unitholders net of Preferred Unit distributions, including accretion of the Preferred Unit beneficial conversion feature. In the event of net income, diluted net income per partner unit reflected the potential dilution of non-vested restricted stock awards and the conversion of Preferred Units. On June 4, 2020, as part of the Recapitalization Transactions, the general partner units were converted to common units; therefore, net income or loss will no longer be allocated to our general partner.
20
Note 10. Related Party Transactions
Agreements with Affiliates
The following agreements were negotiated among affiliated parties and, consequently, are not the result of arm’s length negotiations. The following is a description of those agreements that were entered into with the affiliates of our former board member and Chief Executive Officer, Mr. Charles R. Olmstead.
Services Agreement
As of June 30, 2020, we were party to a services agreement with our former affiliate, Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provided certain services to us, including managerial, administrative and operational services. The operational services included marketing, geological and engineering services. We reimbursed Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurred in its performance under the services agreement. These expenses included, among other things, salary, bonus, incentive compensation and other amounts paid to persons who performed services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. These expenses were included in G&A in our unaudited condensed consolidated statements of operations.
The Partnership entered into a master services agreement with Contango Resources on June 4, 2020, as part of the Recapitalization Transaction. Under the agreement, Contango Resources will provide management and administrative services and serve as operator of the Partnership’s assets for a flat fee arrangement of $4.0 million annually, plus a maximum $2.0 million termination fee, effective July 1, 2020.
Operating Agreements
As of June 30, 2020, we, along with various third parties with an ownership interest in the same property, were parties to standard oil and natural gas joint operating agreements with our former affiliate, Mid-Con Energy Operating. We and those third parties paid Mid-Con Energy Operating overhead associated with operating our properties and for its direct and indirect expenses that were chargeable to the wells under their respective operating agreements. The majority of these expenses were included in LOE in our unaudited condensed consolidated statements of operations. Mid-Con Energy Operating resigned as operator under these joint operating agreements and Contango Resources became operator on July 1, 2020. Pursuant to the MSA with Contango Resources, Contango Resources will not charge overhead associated with operating our properties.
Oilfield Services
As of June 30, 2020, we were party to operating agreements, pursuant to which our former affiliate, Mid-Con Energy Operating, billed us for oilfield services performed by our affiliates, ME3 Oilfield Service and ME2 Well Services, LLC. These amounts were either included in LOE in our unaudited condensed consolidated statements of operations or were capitalized as part of oil and natural gas properties in our unaudited condensed consolidated balance sheets. Mid-Con Energy Operating resigned as operator under these service agreements, and Contango Resources became operator, on July 1, 2020.
Other Agreements
During the six months ended June 30, 2020, we were party to monitoring fee agreements with Bonanza Fund Management, Inc. (“Bonanza”), a Class A Preferred Unitholder, and Goff Focused Strategies, LLC (“GFS”), a Class B Preferred Unitholder, pursuant to which we paid Bonanza and GFS a quarterly monitoring fee in connection with monitoring the purchasers’ investments in the Preferred Units. These expenses were included in G&A in our unaudited condensed consolidated statements of operations.
The following table summarizes the related party transactions for the periods indicated:
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
(in thousands)
|
|
2020
|
|
|
2019
|
|
|
2020
|
|
|
2019
|
|
Services agreement
|
|
$
|
1,180
|
|
|
$
|
708
|
|
|
$
|
2,600
|
|
|
$
|
1,477
|
|
Operating agreements
|
|
|
2,492
|
|
|
|
2,708
|
|
|
|
5,023
|
|
|
|
5,544
|
|
Oilfield services
|
|
|
923
|
|
|
|
1,415
|
|
|
|
2,657
|
|
|
|
2,512
|
|
Other agreements
|
|
|
36
|
|
|
|
80
|
|
|
|
116
|
|
|
|
160
|
|
|
|
$
|
4,631
|
|
|
$
|
4,911
|
|
|
$
|
10,396
|
|
|
$
|
9,693
|
|
21
At June 30, 2020, we had a payable to Contango Resources of $1.3 million for accrued joint interest billings. At June 30, 2020, we had a net payable to our former affiliate, Mid-Con Energy Operating, of $0.7 million, comprised of a joint interest billing payable of $1.1 million and a payable for operating services and other miscellaneous items of $0.2 million, offset by an oil and natural gas revenue receivable of $0.6 million. At December 31, 2019, we had a net payable to our affiliate, Mid-Con Energy Operating, of $6.9 million, comprised of a joint interest billing payable of $7.8 million and a payable for operating services and other miscellaneous items of $0.8 million, offset by an oil and natural gas revenue receivable of $1.7 million. These amounts were included in accounts payable-related parties in our unaudited condensed consolidated balance sheets.
Note 11. Revenue Recognition
Revenue from Contracts with Customers
Under our oil and natural gas sales contracts, enforceable rights and obligations arise at the time production occurs on dedicated leases as the Partnership promises to deliver goods in the form of oil or natural gas production on contractually-specified leases to the purchasers. Sales of oil and natural gas are recognized at the point that control of the product is transferred to the customer; title and risk of loss to the product generally transfers at the delivery point specified in the contract. We do not extract natural gas liquids (“NGLs”) from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extracted NGLs from the natural gas stream sold by us to them, we had no ownership in such NGLs. The Partnership commits and dedicates for sale all of the oil or natural gas production from contractually agreed-upon leases to the purchaser. Our oil contract pricing provisions are tied to a market index, with certain marketing adjustments, including location and quality differentials as well as certain embedded marketing fees. The majority of our natural gas contract pricing provisions are tied to a market index less customary deductions, such as gathering, processing and transportation. Payment is typically received 30 to 60 days after the date production is delivered. We had no significant natural gas imbalances at June 30, 2020 and 2019.
Transaction Price Allocated to Remaining Performance Obligations
Our oil and natural gas sales are generally short-term in nature, with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14, exempting the Partnership from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For our oil and natural gas sales contracts, the variable consideration related to variable production is not estimated because the uncertainty related to the consideration is resolved as the barrel of oil (“Bbl”) and Mcf of natural gas are transferred to the customer each day. Therefore, we have utilized the practical expedient in ASC 606-10-50-14(a), which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations for specific situations in which the Partnership does not need to estimate variable consideration to recognize revenue.
Contract Balances
Our oil and natural gas sales contracts do not give rise to contract assets or liabilities under ASC 606.
Note 12. Leases
We adopted ASC 842, as amended, on January 1, 2019, using the modified retrospective approach. The modified retrospective approach provided a method for recording existing leases at adoption and allowed for a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The adoption of this standard did not result in an adjustment to retained earnings. We elected the transition package of practical expedients permitted under the transition guidance, which among other things, allowed us to carry forward the historical lease classification. We also elected the optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840, Leases (“ASC 840”). Our leases do not provide an implicit discount rate; therefore, we used our incremental borrowing rate as of January 1, 2019. As a result of adopting the new standard, we recorded lease assets and lease liabilities of $1.2 million and $1.3 million, respectively, at January 1, 2019.
We lease office space in Tulsa, Oklahoma, Abilene, Texas, and Gillette, Wyoming. Per the short-term accounting policy election, leases with an initial term of 12 months or less were not recorded on the balance sheet, and we recognize lease expense for these leases on a straight-line basis over the term of the lease. Most of our leases include an option to renew. The exercise of the lease renewal options is at our discretion.
22
A summary of our leases is presented below:
(in thousands)
|
|
Classification
|
|
Six Months Ended
June 30, 2020
|
|
|
Year Ended
December 31, 2019
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
Other property and equipment
|
|
$
|
564
|
|
|
$
|
835
|
|
Total lease assets
|
|
|
|
$
|
564
|
|
|
$
|
835
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
Current operating
|
|
Other current liabilities
|
|
$
|
445
|
|
|
$
|
430
|
|
Non-current operating
|
|
Other long-term liabilities
|
|
|
230
|
|
|
|
457
|
|
Total lease liabilities
|
|
|
|
$
|
675
|
|
|
$
|
887
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
|
|
Classification
|
|
2020
|
|
|
2019
|
|
|
2020
|
|
|
2019
|
|
Operating lease expense(1)(2) (in thousands)
|
|
G&A expense
|
|
$
|
146
|
|
|
$
|
65
|
|
|
$
|
218
|
|
|
$
|
131
|
|
Weighted average remaining lease term (months)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
|
|
18
|
|
|
|
29
|
|
|
|
18
|
|
|
|
29
|
|
Weighted average discount rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
|
|
5.7
|
%
|
|
|
5.7
|
%
|
|
|
5.7
|
%
|
|
|
5.7
|
%
|
(1) Includes short-term leases.
(2) There is not a material difference between cash paid and amortized expense.
Future minimum lease payments under the non-cancellable operating leases are presented in the following table:
(in thousands)
|
|
Operating Leases
|
|
Remaining 2020
|
|
$
|
240
|
|
2021
|
|
|
471
|
|
Total lease maturities
|
|
|
711
|
|
Less: interest
|
|
|
36
|
|
Present value of lease liabilities
|
|
$
|
675
|
|
Note 13. New Accounting Standards
In June 2016, the FASB issued ASC 326, Financial Instruments- Credit Losses (“ASC 326”), which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. For smaller reporting companies, this guidance is effective for fiscal years beginning after December 15, 2022, and early adoption is permitted. We plan to adopt this standard on January 1, 2023, and are currently evaluating the impact of the adoption on our consolidated financial statements.
Note 14. Subsequent Events
Appointment and Departure of Officers
On July 6, 2020, the Partnership announced the resignation of Mr. Chad B. Roller, President and Chief Operating Officer, and Mr. Charles L. McLawhorn, III, Vice President, General Counsel and Corporate Secretary to pursue opportunities with Contango Oil & Gas Company. Messrs. Roller and McLawhorn will continue to provide services to the Partnership pursuant to that Management Services Agreement.
On August 6, 2020, the Partnership announced the resignation of Mr. Philip R. Houchin as Chief Financial Officer. Effective July 31, 2020, Ms. Sherry L. Morgan was appointed as Chief Executive Officer, Mr. Greg Westfall was appointed as Chief Operating Officer and Ms. Jodie L. DiGiacomo was appointed as Chief Accounting Officer.
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