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. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company.
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, 2018, 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 to be expected 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.
Reclassifications
The unaudited condensed consolidated statements of operations for the prior year period presented includes reclassifications from lease operating expenses (“LOE”) to production and ad valorem taxes to conform to the current presentation. Such reclassifications have no impact on previously reported net loss.
Non-cash Investing and Supplemental Cash Flow Information
The following presents the non-cash investing and supplemental cash flow information for the periods presented:
|
|
Three Months Ended
March 31,
|
|
(in thousands)
|
|
2019
|
|
|
2018
|
|
Non-cash investing information
|
|
|
|
|
|
|
|
|
Change in oil and natural gas properties - assets received in exchange
|
|
$
|
38,533
|
|
|
$
|
—
|
|
Change in oil and natural gas properties - accrued capital expenditures
|
|
$
|
58
|
|
|
$
|
132
|
|
Change in oil and natural gas properties - accrued acquisitions
|
|
$
|
(954
|
)
|
|
$
|
(86
|
)
|
Change in oil and natural gas properties - acquisition deposit paid in prior year
|
|
$
|
—
|
|
|
$
|
1,000
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
1,677
|
|
|
$
|
892
|
|
9
Note 2.
Acquisitions, Divestitures and Assets Held for Sale
Acquisitions
We adopted ASU No. 2017-01, “
Business Combinations
(Topic 805)” effective January 1, 2018. We now evaluate all acquisitions to determine whether they should be accounted for as business combinations or asset acquisitions. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and substantive process that together significantly contribute to the ability to create output.
Acquisitions – Business Combinations
The assets and liabilities assumed in acquisitions accounted for as business combinations were 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 were included in our unaudited condensed consolidated statements of operations.
Pine Tree
In January 2018, we acquired multiple oil and natural gas properties located in Campbell and Converse Counties, Wyoming (the “Pine Tree” acquisition). Pine Tree was accounted for as a business combination. We acquired Pine Tree for cash consideration of $8.4 million, after final post-closing purchase price adjustments.
The recognized fair values of the Pine Tree assets acquired and liabilities assumed are as follows:
(in thousands)
|
|
|
|
|
Fair value of net assets acquired
|
|
|
|
|
Proved oil and natural gas properties
|
|
$
|
8,833
|
|
Total assets acquired
|
|
|
8,833
|
|
Fair value of net liabilities assumed
|
|
|
|
|
Asset retirement obligation
|
|
|
463
|
|
Net assets acquired
|
|
$
|
8,370
|
|
The following table presents revenues and expenses of the acquired oil and natural gas properties included in the accompanying unaudited condensed consolidated statements of operations for the periods presented:
|
|
Three Months Ended
March 31,
|
|
(in thousands)
|
|
2019
|
|
|
2018
|
|
Oil and natural gas sales
|
|
$
|
222
|
|
|
$
|
130
|
|
Expenses
(1)
|
|
$
|
208
|
|
|
$
|
120
|
|
(1)
Expenses include LOE, production and ad valorem taxes, accretion and depletion.
Divestitures
Effective at closing, the operations and cash flows of the following divested properties were eliminated from our ongoing operations, and we have no continuing involvement in these properties.
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 a purchase price of $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 on our
10
revolving credit facility.
The acquired properties were accounted for as an asset acquisition. A g
ain on the sale of oil and natural gas properties of $9.5
million was reported
in the unaudited condensed consolidated statements of operations
.
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
March 31,
|
|
(in thousands)
|
|
2019
|
|
|
2018
|
|
Oil and natural gas sales
|
|
$
|
4,650
|
|
|
$
|
6,968
|
|
Expenses
(1)
|
|
$
|
3,374
|
|
|
$
|
4,418
|
|
(1)
Expenses include LOE, production and ad valorem taxes, dry hole and abandonment, accretion and depletion.
Nolan County
In January 2018, we completed the sale of certain oil and natural gas proved properties in Nolan County, Texas, for $1.5 million, after final post-closing purchase price adjustments. These properties were deemed to meet held-for-sale accounting criteria as of December 31, 2017, and impairment of $0.3 million was recorded to reduce the carrying value of these assets to their estimated fair value of $1.5 million at December 31, 2017; therefore, no gain or loss was realized on the sale in 2018.
Assets Held for Sale
Land in Southern Oklahoma met held-for-sale criteria as of March 31, 2019, and December 31, 2018. The carrying value of $0.4 million was presented as “Assets held for sale, net” in our unaudited condensed consolidated balance sheets.
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 affiliates, including Mid-Con Energy Operating, LLC (“Mid-Con Energy Operating”) and ME3 Oilfield Service, LLC (“ME3 Oilfield Service”), who perform 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 Charles R. Olmstead, Executive Chairman of the Board, and Jeffrey R. Olmstead, President and Chief Executive Officer, 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 March 31, 2019:
|
|
Number of
Common Units
|
|
Approved and authorized awards
|
|
|
3,514,000
|
|
Unrestricted units granted
|
|
|
(1,350,538
|
)
|
Restricted units granted, net of forfeitures
|
|
|
(399,424
|
)
|
Equity-settled phantom units granted, net of forfeitures
|
|
|
(1,493,669
|
)
|
Awards available for future grant
|
|
|
270,369
|
|
We recognized $0.3 million and $0.2 million of total equity-based compensation expense for the three months ended March 31, 2019 and 2018, respectively. 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 three months ended March 31, 2019, we granted 50,000 unrestricted units with an average grant date fair value of $1.04 per unit. During the three months ended March 31, 2018, we granted 87,832 unrestricted units with an average grant date fair value of $1.79 per unit.
11
Equity-Settled Phantom Unit Awards
Equity-settled phantom units vest over a period of two or three years. During the three months ended March 31, 2019, we granted 510,000 equity-settled phantom units with a two-year vesting period and 63,000 equity-settled phantom units with a three-year vesting period. During the three months ended March 31, 2018, we granted 381,000 equity-settled phantom units with
a two-year vesting period and 8,500 equity-settled phantom units with a three-year vesting period
. As of March 31, 2019, there were $0.7 million of unrecognized compensation costs related to non-vested equity-settled phantom units. These costs are expected to be recognized over a weighted average period of nineteen months.
A summary of our equity-settled phantom unit awards for the three months ended March 31, 2019, is presented below:
|
|
Number of
Equity-Settled
Phantom Units
|
|
|
Average Grant Date
Fair Value per Unit
|
|
Outstanding at December 31, 2018
|
|
|
351,166
|
|
|
$
|
1.73
|
|
Units granted
|
|
|
573,000
|
|
|
|
1.04
|
|
Units vested
|
|
|
(299,834
|
)
|
|
|
1.35
|
|
Units forfeited
|
|
|
(12,000
|
)
|
|
|
1.75
|
|
Outstanding at March 31, 2019
|
|
|
612,332
|
|
|
$
|
1.27
|
|
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 (commodity price and differential 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 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 March 31, 2019, our commodity derivative contracts were in a net liability position with a fair value of $4.3 million, whereas at December 31, 2018, our commodity derivative contracts were in a net asset position with a fair value of $8.1 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 March 31, 2019, all of our counterparties have performed pursuant to the terms of their commodity derivative contracts.
12
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
March 31, 2019, and December 31, 2018
:
(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
|
|
March 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - long-term asset
|
|
$
|
1,360
|
|
|
$
|
(1,360
|
)
|
|
$
|
—
|
|
Total
|
|
|
1,360
|
|
|
|
(1,360
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current liability
|
|
|
(2,928
|
)
|
|
|
—
|
|
|
|
(2,928
|
)
|
Derivative financial instruments - long-term liability
|
|
|
(2,689
|
)
|
|
|
1,360
|
|
|
|
(1,329
|
)
|
Total
|
|
|
(5,617
|
)
|
|
|
1,360
|
|
|
|
(4,257
|
)
|
Net Liability
|
|
$
|
(4,257
|
)
|
|
$
|
—
|
|
|
$
|
(4,257
|
)
|
(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, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current asset
|
|
$
|
5,705
|
|
|
$
|
(39
|
)
|
|
$
|
5,666
|
|
Derivative financial instruments - long-term asset
|
|
|
2,418
|
|
|
|
—
|
|
|
|
2,418
|
|
Total
|
|
|
8,123
|
|
|
|
(39
|
)
|
|
|
8,084
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current liability
|
|
|
(39
|
)
|
|
|
39
|
|
|
|
—
|
|
Total
|
|
|
(39
|
)
|
|
|
39
|
|
|
|
—
|
|
Net Asset
|
|
$
|
8,084
|
|
|
$
|
—
|
|
|
$
|
8,084
|
|
The following table presents the impact of derivative financial instruments and their location within the unaudited condensed consolidated statements of operations:
|
|
Three Months Ended
March 31,
|
|
(in thousands)
|
|
2019
|
|
|
2018
|
|
Net settlements on matured derivatives
(1)
|
|
$
|
143
|
|
|
$
|
(1,324
|
)
|
Net change in fair value of derivatives
|
|
|
(12,341
|
)
|
|
|
(2,058
|
)
|
Total loss on derivatives, net
|
|
$
|
(12,198
|
)
|
|
$
|
(3,382
|
)
|
(1)
The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.
13
At
March 31, 2019
, and December 31
, 2018
, our commodity derivative contracts had maturities at various dates
through December 2021
and were comprised of commodity price
and differential
swap
s
and
collar
contracts. At
March 31, 2019
, we had the following oil derivatives net positions:
Period Covered
|
|
Differential Fixed Price
|
|
|
Weighted Average Fixed Price
|
|
|
Weighted Average Floor Price
|
|
|
Weighted Average Ceiling Price
|
|
|
Total Bbls
Hedged/day
|
|
|
Index
|
Swaps - 2019
|
|
$
|
—
|
|
|
$
|
56.10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
1,727
|
|
|
NYMEX-WTI
|
Swaps - 2019
|
|
$
|
(20.15
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
150
|
|
|
WCS-CRUDE-OIL
|
Swaps - 2020
|
|
$
|
—
|
|
|
$
|
55.81
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
1,931
|
|
|
NYMEX-WTI
|
Swaps - 2021
|
|
$
|
—
|
|
|
$
|
55.78
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
672
|
|
|
NYMEX-WTI
|
Collars - 2021
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
52.00
|
|
|
$
|
58.80
|
|
|
|
672
|
|
|
NYMEX-WTI
|
At December 31, 2018, we had the following oil derivatives net positions:
Period Covered
|
|
Differential Fixed Price
|
|
|
Weighted Average Fixed Price
|
|
|
Total Bbls
Hedged/day
|
|
|
Index
|
Swaps - 2019
|
|
$
|
—
|
|
|
$
|
56.14
|
|
|
|
1,779
|
|
|
NYMEX-WTI
|
Swaps - 2019
|
|
$
|
(20.15
|
)
|
|
$
|
—
|
|
|
|
137
|
|
|
WCS-CRUDE-OIL
|
Swaps - 2020
|
|
$
|
—
|
|
|
$
|
54.81
|
|
|
|
1,199
|
|
|
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.
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
14
assets or liabilities. We had no transfers in
or out of Levels 1, 2 or 3 for the
three months ended March 31, 2019
, and for
the year ended December 31, 2018
.
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 months ended March 31, 2019, and for the year ended December 31, 2018.
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 its 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 March 31, 2019, and December 31, 2018:
(in thousands)
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Fair Value
|
|
March 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - asset
|
|
$
|
—
|
|
|
$
|
1,360
|
|
|
$
|
—
|
|
|
$
|
1,360
|
|
Derivative financial instruments - liability
|
|
$
|
—
|
|
|
$
|
5,617
|
|
|
$
|
—
|
|
|
$
|
5,617
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - asset
|
|
$
|
—
|
|
|
$
|
8,123
|
|
|
$
|
—
|
|
|
$
|
8,123
|
|
Derivative financial instruments - liability
|
|
$
|
—
|
|
|
$
|
39
|
|
|
$
|
—
|
|
|
$
|
39
|
|
A summary of the changes in Level 3 fair value measurements for the periods presented are as follows:
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Three Months Ended
March 31, 2019
|
|
|
Year Ended
December 31, 2018
|
|
Balance of Level 3 at beginning of period
|
|
$
|
—
|
|
|
$
|
(401
|
)
|
Derivative deferred premiums - settlements
|
|
|
—
|
|
|
|
401
|
|
Balance of Level 3 at end of period
|
|
$
|
—
|
|
|
$
|
—
|
|
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 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. 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
15
proved properties include estimates of reserves, future operating and developmental costs, future commodity prices, a market-based weighted average cost of capital rat
e 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 int
ernal 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. There was no impairment expense for the three months ended March 31, 2019. We recorded impairment expense of $8.8 million for the three months ended March 31, 2018.
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.
As of March 31, 2019, and December 31, 2018, 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)
|
|
Three Months Ended
March 31, 2019
|
|
|
Year Ended
December 31, 2018
|
|
Asset retirement obligations - beginning of period
|
|
$
|
26,001
|
|
|
$
|
10,326
|
|
Liabilities incurred for new wells and interest
|
|
|
8,913
|
|
|
|
15,497
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
—
|
|
|
|
(138
|
)
|
Liabilities removed upon sale of wells
|
|
|
(5,462
|
)
|
|
|
(399
|
)
|
Revision of estimates
|
|
|
—
|
|
|
|
(6
|
)
|
Accretion expense
|
|
|
328
|
|
|
|
721
|
|
Asset retirement obligations - end of period
|
|
$
|
29,780
|
|
|
$
|
26,001
|
|
Note 7. Debt
We had outstanding borrowings under our revolving credit facility of $68.0 million and $93.0 million at March 31, 2019, and December 31, 2018, respectively. Our current revolving credit facility matures in November 2020. Borrowings under the facility are secured by liens on not less than 90% of the value of our proved reserves.
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. The next regularly scheduled semi-annual redetermination is expected to occur in the fall of 2019.
16
Borrowings under the revolving credit facility bear int
erest 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 wh
ich 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 tha
t varies from 2.75% to 3.75% per annum according to the borrowing base usage. For the three months ended
March 31, 2019
, the average effective rate was
5.77
%
. Any unused porti
on 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 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 January 31, 2018, Amendment 12 to the credit agreement was executed, extending the maturity of our credit facility from November 2018 until November 2020 and
increasing the borrowing base of our revolving credit facility to $125.0 million. The lenders also waived any default or event of default that occurred as a result of our failure to maintain the required leverage ratios for the quarter ended September 30, 2017. The amendment also required us to have a minimum liquidity of 20% to make cash distributions to the Preferred Unitholders.
During the fall 2018 semi-annual borrowing base redetermination of our revolving credit facility completed in December 2018, the lender group increased our borrowing base to $135.0 million effective December 19, 2018. There were no changes to the terms or conditions of the credit agreement.
On March 28, 2019, in conjunction with closing the Strategic Transaction, 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 the second quarter of 2019. As of March 31, 2019, we were in compliance with our financial covenants.
See Note 2 in this section for further discussion of the Strategic Transaction.
Note 8. Commitments and Contingencies
Services Agreement
We are party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provides certain services to us including management, administrative and operational services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. See Note 10 in this section for additional information.
Employment Agreements
Our general partner has entered into employment agreements with Charles R. Olmstead, Executive Chairman of the Board and Jeffrey R. Olmstead, President and Chief Executive Officer. The employment agreements automatically renew for one-year terms on August 1st of each year unless either we or the employee gives written notice of termination by the preceding February. Pursuant to the employment agreements, each employee will serve in his respective position with our general partner, as set forth above, and has duties, responsibilities and authority as the Board may specify from time to time, in roles consistent with such positions that are assigned to them. The agreements stipulate that if there is a change of control, termination of employment, with cause or without cause, or death of the executive certain payments will be made to the executive officer. These payments, depending on the reason for termination, currently range from $0.3 million to $0.7 million, including the value of vesting of any outstanding units.
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.
17
Note 9. Equity
Common Units
At March 31, 2019, and December 31, 2018, the Partnership’s equity consisted of
30,785,958
and 30,436,124 common units, respectively, representing a 98.8% limited partnership interest in us.
On May 5, 2015, we entered into an Equity Distribution Agreement to sell, from time to time through or to the Managers (as defined in the agreement), up to $50.0 million in common units representing limited partner interests. In connection with the purchase agreement for the Class A Preferred Units described below, we suspended sales of common units pursuant to the Equity Distribution Agreement effective as of the closing date until August 11, 2021, without the consent of a majority of the holders of the outstanding Preferred Units.
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 March 31, 2019, 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 has issued two classes of 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 is 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 is 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 are entitled to certain rights that are senior to the rights of holders of common units, such as rights to distributions and rights upon liquidation of the Partnership. We pay 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 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%. Such distributions will be paid for each such quarter within 45 days after such quarter end, or as otherwise permitted to accumulate pursuant to the Partnership Agreement.
Prior to August 11, 2021, each holder of Preferred Units has the right, subject to certain conditions, to convert all or a portion of their Preferred Units into common units representing limited partner interests in the Partnership 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 will 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.
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) and the beneficial conversion feature ($6.0 million). Accretion of the beneficial conversion feature was $0.3 million for the three months ended March 31, 2019 and 2018. The registration statement registering resales of common units issued or to be issued upon conversion of the Class A Preferred Units was declared effective by the SEC on June 14, 2017.
18
At
March 31,
2019
, the Partnership had accrued $0.5 million for the
first
quarter 201
9
distribution
s
that will be paid in cash in
May 2019
.
The following table summarizes cash distributions paid on our Class A Preferred Units during the
three months ended March 31, 201
9
:
Date Paid
|
|
Period Covered
|
|
Distribution per
Unit
|
|
|
Total Distributions
(in thousands)
|
|
February 14, 2019
|
|
October 1, 2018 - December 31, 2018
|
|
$
|
0.0430
|
|
|
$
|
500
|
|
The following table summarizes cash distributions paid on our Class A Preferred Units during the three months ended March 31, 2018:
Date Paid
|
|
Period Covered
|
|
Distribution per
Unit
|
|
|
Total Distributions
(in thousands)
|
|
February 14, 2018
|
|
July 1, 2017 - December 31, 2017
|
|
$
|
0.0860
|
|
|
$
|
1,000
|
|
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 $0.05 million and $0.03 million for the three months ended March 31, 2019 and 2018, respectively. The registration statement registering resales of common units issued or to be issued upon conversion of the Class B Preferred Units was declared effective by the SEC on May 25, 2018.
At March 31, 2019, the Partnership had accrued $0.3 million for the first quarter 2019 distributions that will be paid in cash in May 2019. The following table summarizes cash distributions paid on our Class B Preferred Units during the three months ended March 31, 2019:
Date Paid
|
|
Period Covered
|
|
Distribution per
Unit
|
|
|
Total Distributions
(in thousands)
|
|
February 14, 2019
|
|
October 1, 2018 - December 31, 2018
|
|
$
|
0.0306
|
|
|
$
|
300
|
|
Allocation of Net Income or Loss
Net income or loss is allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss is 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 reflects the potential dilution of non-vested restricted stock awards and the conversion of Preferred Units.
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 have been entered into with the affiliates of our general partner and with our general partner.
Services Agreement
We are party to a services agreement with our affiliate, Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provides certain services to us, including managerial, administrative and operational services. The operational services include marketing, geological and engineering services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform
19
services for us or on our behalf and other expenses all
ocated by Mid-Con Energy Operating to us. These expenses are included in G&A in our unaudited condensed consolidated statements of operations.
Operating Agreements
We, along with various third parties with an ownership interest in the same property, are parties to standard oil and natural gas joint operating agreements with our affiliate, Mid-Con Energy Operating. We and those third parties pay Mid-Con Energy Operating overhead associated with operating our properties and for its direct and indirect expenses that are 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.
Oilfield Services
We are party to operating agreements, pursuant to which our affiliate, Mid-Con Energy Operating, bills us for oilfield services performed by our affiliates, ME3 Oilfield Service and ME2 Well Services, LLC. These amounts are either included in LOE in our unaudited condensed consolidated statements of operations or are capitalized as part of oil and natural gas properties in our unaudited condensed consolidated balance sheets.
Other Agreements
We are 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 pay 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
|
|
|
|
March 31,
|
|
(in thousands)
|
|
2019
|
|
|
2018
|
|
Services agreement
|
|
$
|
769
|
|
|
$
|
530
|
|
Operating agreements
|
|
|
2,836
|
|
|
|
1,326
|
|
Oilfield services
|
|
|
1,097
|
|
|
|
911
|
|
Other Agreements
|
|
|
80
|
|
|
|
70
|
|
|
|
$
|
4,782
|
|
|
$
|
2,837
|
|
At March 31, 2019, we had a net payable to our affiliate, Mid-Con Energy Operating, of $1.2 million, comprised of a joint interest billing payable of $2.7 million and a payable for operating services and other miscellaneous items of $0.3 million, offset by an oil and natural gas revenue receivable of $1.8 million. At December 31, 2018, we had a net payable to our affiliate, Mid-Con Energy Operating, of $3.7 million, comprised of a joint interest billing payable of $3.7 million and a payable for operating services and other miscellaneous items of $1.2 million, offset by an oil and natural gas revenue receivable of $1.2 million. These amounts were included in accounts payable-related parties in our unaudited condensed consolidated balance sheets.
Note 11. New Accounting Standards
On January 1, 2019, we adopted ASC 842,
Leases
(“ASC 842”). See Note 13 in this section for further discussion of ASC 842.
Note 12. Revenue Recognition
We adopted ASC 606 effective January 1, 2018, using the modified retrospective approach. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Under ASC 605, we followed the sales method of accounting for oil and natural gas sales revenues in which revenues were recognized on our share of actual proceeds from oil and natural gas sold to purchasers. Revenue recognition required for our oil and natural gas sales contracts by ASC 606 does not differ from revenue recognition required under ASC 605 to account for such contracts. Therefore, we concluded that there was no change in our revenue recognition
20
under ASC 606 and the cumulative effect of applying t
he new standard to all outstanding contracts as of January 1, 2018, did not result in an adjustment to retained earnings.
We had no significant natural gas imbalances at March 31, 2019 and 2018. During the periods ended March 31, 2019 and 2018, we did not
extract 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 ownershi
p in such NGLs.
Therefore, we did
not report NGLs in our production or proved reserves.
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. The Partnership commits and dedicates for sale all of the crude 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. Our natural gas sales revenues are a percentage of the proceeds received by the purchaser for selling the volume of gas produced by the Partnership on a monthly basis. The purchaser sells the volume of natural gas at index rates per Mcf. Payment is typically received 30 to 60 days after the date production is delivered.
Transaction Price Allocated to Remaining Performance Obligations
Our product 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 crude oil sales 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 product sales contracts do not give rise to contract assets or liabilities under ASC 606.
Note 13. 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, as of 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 one or more options to renew. The exercise of the lease renewal options is at our discretion.
21
A summary of our leases is presented below:
(in thousands)
|
|
Classification
|
|
Three Months Ended
March 31, 2019
|
|
|
Year Ended
December 31, 2018
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
Other property and equipment
|
|
$
|
1,125
|
|
|
$
|
—
|
|
Total lease assets
|
|
|
|
$
|
1,125
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
Current operating
|
|
Other current liabilities
|
|
$
|
408
|
|
|
$
|
—
|
|
Non-current operating
|
|
Other long-term liabilities
|
|
|
782
|
|
|
|
—
|
|
Total lease liabilities
|
|
|
|
$
|
1,190
|
|
|
$
|
—
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
|
|
Classification
|
|
2019
|
|
|
2018
|
|
Operating lease expense
(1)(2)
(in thousands)
|
|
G&A expense
|
|
$
|
66
|
|
|
$
|
65
|
|
Weighted average remaining lease term (months)
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
|
|
32
|
|
|
|
44
|
|
Weighted average discount rate
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
|
|
5.7
|
%
|
|
|
(3
|
)
|
(1)
Includes short-term leases.
(2)
There is not a material difference between cash paid and amortized expense.
(3)
Not applicable under ASC 840.
Future minimum lease payments under the non-cancellable operating leases are presented in the following table:
(in thousands)
|
|
Operating Leases
|
|
Remaining 2019
|
|
$
|
360
|
|
2020
|
|
|
469
|
|
2021
|
|
|
472
|
|
Total lease maturities
|
|
|
1,301
|
|
Less: interest
|
|
|
111
|
|
Present value of lease liabilities
|
|
$
|
1,190
|
|
Note 14. Subsequent Events
Distributions
On May 1, 2019, the Partnership announced that the Board declared Preferred Unit distributions for the first quarter of 2019, according to terms outlined in the Partnership Agreement. Distributions will be paid on May 15, 2019, to holders of record as of the close of business on May 7, 2019. The Class A Preferred Unit cash distributions will be $0.0430 per Class A Preferred Unit, or $0.5 million in aggregate. Additionally, the Class B Preferred Unit cash distributions will be $0.0306 per Class B Preferred Unit, or $0.3 million in aggregate.