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, exploitation and development of producing oil and natural gas properties in North America, with a focus on enhanced oil recovery (“EOR”). Our common units representing limited partner interests in us (“common units”) are listed on the National Association of Securities Dealers Automated Quotation System Global Select Market (“NASDAQ”) under the symbol “MCEP.” 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, 2016, 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
Certain amounts in the financial statements for the prior years have been reclassified to conform to the 2017 presentation. These reclassifications have no impact on previously reported total assets, total liabilities, net income (loss) or total operating cash flows.
Non-cash Investing, Financing and Supplemental Cash Flow Information
The following presents the non-cash investing, financing and supplemental cash flow information for the periods presented:
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
(in thousands)
|
|
Non-cash investing information
|
|
|
|
|
|
|
|
|
Change in oil and natural gas properties - accrued
|
|
$
|
885
|
|
|
$
|
(513
|
)
|
Change in oil and natural gas properties - accrued receivable, acquisition post-close
|
|
$
|
—
|
|
|
$
|
(419
|
)
|
Change in oil and natural gas properties - accrued receivable, divestiture post-close
|
|
$
|
—
|
|
|
$
|
(354
|
)
|
Change in other property and equipment - accrued
|
|
$
|
—
|
|
|
$
|
14
|
|
Change in other property and equipment - tenant improvement allowance
|
|
$
|
—
|
|
|
$
|
124
|
|
Non-cash financing information
|
|
|
|
|
|
|
|
|
Change in Class A Preferred Units - accrued offering costs
|
|
$
|
—
|
|
|
$
|
(302
|
)
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
3,566
|
|
|
$
|
5,063
|
|
9
Note 2. Acquisitions and Divestitures
Acquisitions
Acquisitions are accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in acquisitions 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.
Permian Bolt-On
In August 2016, we acquired multiple oil and natural gas properties located in Nolan County, Texas (the “Permian Bolt-On”) for cash consideration of approximately $18.7 million, after post-closing purchase price adjustments. The transaction was funded by a private offering of $25.0 million Class A Convertible Preferred Units (“Class A Preferred Units”). See Note 9 in this section for additional information regarding the issuance of the Class A Preferred Units. For the three months and nine months ended September 30, 2017, our unaudited condensed consolidated statements of operations included revenues of approximately
$2.0 million and approximately $6.2 million, respectively,
and expenses of approximately $1.4 million and approximately $4.3 million, respectively, related to the oil and natural gas properties acquired. For the three and nine months ended September 30, 2016, our unaudited condensed consolidated statements of operations included revenues of approximately $0.8 million and expenses of approximately
$0.7 million
related to the oil and natural gas properties acquired. The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):
Fair value of net assets acquired
|
|
|
|
|
Oil and natural gas properties
|
|
$
|
19,323
|
|
Total assets acquired
|
|
|
19,323
|
|
Fair value of net liabilities assumed
|
|
|
|
|
Asset retirement obligation
|
|
|
622
|
|
Net assets acquired
|
|
$
|
18,701
|
|
Wheatland
In June 2017, we acquired multiple oil and natural gas properties located in Oklahoma County and Cleveland County, Oklahoma (“Wheatland”) for cash consideration of approximately $4.2 million, prior to post-closing purchase price adjustments. For the three months ended September 30, 2017, our unaudited condensed consolidated statements of operations included revenues of approximately
$0.6 million
and expenses of approximately
$0.4 million
related to the oil and natural gas properties acquired. For the nine months ended September 30, 2017, our unaudited condensed consolidated statements of operations included revenues of approximately
$0.7 million
and expenses of approximately
$0.5 million
related to the oil and natural gas properties acquired. The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):
Fair value of net assets acquired
|
|
|
|
|
Oil and natural gas properties
|
|
$
|
4,465
|
|
Other property and equipment
|
|
|
127
|
|
Total assets acquired
|
|
|
4,592
|
|
Fair value of net liabilities assumed
|
|
|
|
|
Asset retirement obligation
|
|
|
407
|
|
Net assets acquired
|
|
$
|
4,185
|
|
Divestitures
Hugoton
In July 2016, we sold the properties located in our Hugoton core area for cash proceeds of approximately $17.6 million, including post-closing purchase price adjustments and recognized a loss of approximately $0.6 million. Additionally, we recorded impairment of proved oil and natural gas properties of approximately $3.6 million when these properties were originally reported as held for sale. For the three months ended September 30, 2016, our unaudited condensed consolidated statements of operations included revenues of approximately
$0.6 million
and expenses of approximately
$0.6 million
related to the oil and natural gas properties sold. For the nine months ended September 30, 2016, our unaudited condensed consolidated statements of operations included revenues of approximately
$3.6 million
and expenses of approximately
$7.7
10
million
related to the oil and natural
gas properties sold. Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Partnership and the Partnership has no continuing involvement in these properties. This divestiture did not repr
esent a strategic shift and did not have a major effect on the Partnership’s operations or financial results.
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”). We account for unrestricted, restricted and equity-settled phantom unit awards as equity awards since they are settled by issuing common units. 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.
On January 1, 2017, we adopted ASU 2016-09
Compensation - Stock Compensation
(Topic 718)
: Improvements to Employee Share-Based Payment Accounting
(“ASU 2016-09”) and elected to recognize forfeitures of equity awards as they occur. The cumulative effect of adopting ASU 2016-09 was determined to be immaterial and no adjustment to retained earnings was made.
The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at September 30, 2017:
|
|
Number of
Common Units
|
|
Approved and authorized awards
|
|
|
3,514,000
|
|
Unrestricted units granted
|
|
|
(1,212,706
|
)
|
Restricted units granted, net of forfeitures
|
|
|
(400,424
|
)
|
Equity-settled phantom units granted, net of forfeitures
|
|
|
(483,000
|
)
|
Awards available for future grant
|
|
|
1,417,870
|
|
We recognized approximately $0.1 million and $0.4 million of total equity-based compensation expense for the three and nine months ended September 30, 2017, respectively, and we recognized approximately $0.3 million and $1.0 million of total equity-based compensation expense for the three and nine months ended September 30, 2016, 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 nine months ended September 30, 2017, we granted 25,400 unrestricted units with an average grant date fair value of $2.65 per unit. During the nine months ended September 30, 2016, we granted 73,932 unrestricted units with an average grant date fair value of $1.20 per unit.
11
Restricted Unit Awards
Restricted units vest over a two- or three-year period. As of September 30, 2017, there were approximately $0.01 million of unrecognized compensation costs related to non-vested restricted units. These costs are expected to be recognized over a weighted average period of approximately four months.
A summary of our restricted unit awards for the nine months ended September 30, 2017, is presented below:
|
|
Number of
Restricted Units
|
|
|
Average Grant Date
Fair Value per Unit
|
|
Outstanding at December 31, 2016
|
|
|
76,922
|
|
|
$
|
5.67
|
|
Units granted
|
|
|
—
|
|
|
|
—
|
|
Units vested
|
|
|
(69,560
|
)
|
|
|
5.76
|
|
Units forfeited
|
|
|
—
|
|
|
|
—
|
|
Outstanding at September 30, 2017
|
|
|
7,362
|
|
|
$
|
4.88
|
|
Equity-Settled Phantom Unit Awards
Equity-settled phantom units vest over a two- or three-year period and do not have any rights or privileges of a common unitholder, including right to distributions, until vesting and the resulting conversion into common units. During the nine months ended September 30, 2017, we granted 27,000 equity-settled phantom units with a two-year vesting period and 14,500 equity-settled phantom units with a three-year vesting period. During the nine months ended September 30, 2016, we granted 347,500 equity-settled phantom units with one-third vesting immediately and the other two-thirds vesting over two years
and 27,000 equity-settled phantom awards with a three-year vesting period
. As of September 30, 2017, there were approximately $0.2 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 approximately thirteen months.
A summary of our equity-settled phantom unit awards for the nine months ended September 30, 2017, is presented below:
|
|
Number of
Equity-
Settled
Phantom Units
|
|
|
Average
Grant Date
Fair Value per
Unit
|
|
Outstanding at December 31, 2016
|
|
|
287,659
|
|
|
$
|
1.64
|
|
Units granted
|
|
|
41,500
|
|
|
|
1.60
|
|
Units vested
|
|
|
(153,833
|
)
|
|
|
1.70
|
|
Units forfeited
|
|
|
(16,000
|
)
|
|
|
2.83
|
|
Outstanding at September 30, 2017
|
|
|
159,326
|
|
|
$
|
1.48
|
|
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 and specific delivery points. 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 to do so, or as required by our lenders. These contracts are presented as derivative financial instruments on our unaudited condensed consolidated financial statements. 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.
12
At
September 30, 2017
, our commodity derivative contracts were in a net liability position with a fair value of approximately $0.6 million and at
December 31, 2016
, a net liability position with a fair value of approximately $7.8 million. All of our commodit
y 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 u
nder lower commodity prices and we could incur a loss. As of
September 30, 2017
, 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 September 30, 2017, and December 31, 2016:
|
|
Gross
Amounts
Recognized
|
|
|
Gross Amounts
Offset in the
Unaudited
Condensed
Consolidated
Balance Sheets
|
|
|
Net Amounts
Presented in
the Unaudited
Condensed
Consolidated
Balance Sheets
|
|
|
|
(in thousands)
|
|
September 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current asset
|
|
$
|
266
|
|
|
$
|
(224
|
)
|
|
$
|
42
|
|
Derivative financial instruments - long-term asset
|
|
|
627
|
|
|
|
(440
|
)
|
|
|
187
|
|
Total
|
|
|
893
|
|
|
|
(664
|
)
|
|
|
229
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current liability
|
|
|
(769
|
)
|
|
|
(15
|
)
|
|
|
(784
|
)
|
Derivative deferred premium - current liability
|
|
|
(239
|
)
|
|
|
239
|
|
|
|
—
|
|
Derivative financial instruments - long-term liability
|
|
|
(239
|
)
|
|
|
239
|
|
|
|
—
|
|
Derivative deferred premium - long-term liability
|
|
|
(201
|
)
|
|
|
201
|
|
|
|
—
|
|
Total
|
|
|
(1,448
|
)
|
|
|
664
|
|
|
|
(784
|
)
|
Net Liability
|
|
$
|
(555
|
)
|
|
$
|
—
|
|
|
$
|
(555
|
)
|
|
|
Gross
Amounts
Recognized
|
|
|
Gross Amounts
Offset in the
Unaudited
Condensed
Consolidated
Balance Sheets
|
|
|
Net Amounts
Presented in
the Unaudited
Condensed
Consolidated
Balance Sheets
|
|
|
|
(in thousands)
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current asset
|
|
$
|
1,570
|
|
|
$
|
(1,570
|
)
|
|
$
|
—
|
|
Derivative financial instruments - long-term asset
|
|
|
406
|
|
|
|
(406
|
)
|
|
|
—
|
|
Total
|
|
|
1,976
|
|
|
|
(1,976
|
)
|
|
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current liability
|
|
|
(1,836
|
)
|
|
|
(3,478
|
)
|
|
|
(5,314
|
)
|
Derivative deferred premium - current liability
|
|
|
(5,048
|
)
|
|
|
5,048
|
|
|
|
—
|
|
Derivative financial instruments - long-term liability
|
|
|
(2,500
|
)
|
|
|
5
|
|
|
|
(2,495
|
)
|
Derivative deferred premium - long-term liability
|
|
|
(401
|
)
|
|
|
401
|
|
|
|
—
|
|
Total
|
|
|
(9,785
|
)
|
|
|
1,976
|
|
|
|
(7,809
|
)
|
Net Liability
|
|
$
|
(7,809
|
)
|
|
$
|
—
|
|
|
$
|
(7,809
|
)
|
13
The following table presents the impact of derivative financial instruments and their location within the unaudited condensed consolidated statements of operations:
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
|
|
(in thousands)
|
|
Net settlements on matured derivatives
(1)
|
|
$
|
323
|
|
|
$
|
1,182
|
|
|
$
|
524
|
|
|
$
|
18,467
|
|
Net settlements on early terminations of derivatives
(1)
|
|
|
147
|
|
|
|
5,820
|
|
|
|
147
|
|
|
|
5,820
|
|
Net change in fair value of derivatives
|
|
|
(3,219
|
)
|
|
|
(7,446
|
)
|
|
|
2,245
|
|
|
|
(32,251
|
)
|
Total (loss) gain on derivatives, net
|
|
$
|
(2,749
|
)
|
|
$
|
(444
|
)
|
|
$
|
2,916
|
|
|
$
|
(7,964
|
)
|
(1
)
The settlement amount does not include premiums paid attributable to contracts that matured or early terminated during the respective period.
At September 30, 2017, and December 31, 2016, our commodity derivative contracts had maturities at various dates through December 2019 and were comprised of commodity price swap, put and collar contracts. At September 30, 2017, we had the following oil derivatives net positions:
Period Covered
|
|
Weighted
Average
Floor Price
|
|
|
Weighted
Average
Ceiling Price
|
|
|
Total Bbls
Hedged/day
|
|
|
NYMEX
Index
|
Swaps - 2017
|
|
$
|
51.54
|
|
|
$
|
-
|
|
|
|
1,957
|
|
|
WTI
|
Collars - 2017
|
|
$
|
45.00
|
|
|
$
|
52.35
|
|
|
|
652
|
|
|
WTI
|
Swaps - 2018
|
|
$
|
50.00
|
|
|
$
|
-
|
|
|
|
164
|
|
|
WTI
|
Collars - 2018
|
|
$
|
44.38
|
|
|
$
|
55.52
|
|
|
|
1,315
|
|
|
WTI
|
Puts - 2018
|
|
$
|
45.00
|
|
|
$
|
-
|
|
|
|
164
|
|
|
WTI
|
Collars - 2019
|
|
$
|
50.00
|
|
|
$
|
60.52
|
|
|
|
427
|
|
|
WTI
|
At December 31, 2016, we had the following oil derivatives net positions:
Period Covered
|
|
Weighted
Average
Floor Price
|
|
|
Weighted
Average
Ceiling Price
|
|
|
Total Bbls
Hedged/day
|
|
|
NYMEX
Index
|
Collars - 2017
|
|
$
|
43.75
|
|
|
$
|
50.68
|
|
|
|
658
|
|
|
WTI
|
Puts - 2017
|
|
$
|
50.00
|
|
|
$
|
—
|
|
|
|
1,932
|
|
|
WTI
|
Collars - 2018
|
|
$
|
44.38
|
|
|
$
|
55.52
|
|
|
|
1,315
|
|
|
WTI
|
Puts - 2018
|
|
$
|
45.00
|
|
|
$
|
—
|
|
|
|
164
|
|
|
WTI
|
Collars - 2019
|
|
$
|
50.00
|
|
|
$
|
60.52
|
|
|
|
427
|
|
|
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 at September 30, 2017, and December 31, 2016.
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 nine months ended September 30, 2017, and for the year ended December 31, 2016.
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. The Partnership’s deferred premiums associated with its commodity derivative contracts are categorized as Level 3, as the Partnership utilizes 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 value of our assets and liabilities measured at fair value on a recurring basis as of September 30, 2017, and December 31, 2016:
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Fair Value
|
|
|
|
(in thousands)
|
|
September 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - asset
|
|
$
|
—
|
|
|
$
|
893
|
|
|
$
|
—
|
|
|
$
|
893
|
|
Derivative financial instruments - liability
|
|
$
|
—
|
|
|
$
|
1,008
|
|
|
$
|
—
|
|
|
$
|
1,008
|
|
Derivative deferred premiums - liability
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
440
|
|
|
$
|
440
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - asset
|
|
$
|
—
|
|
|
$
|
1,976
|
|
|
$
|
—
|
|
|
$
|
1,976
|
|
Derivative financial instruments - liability
|
|
$
|
—
|
|
|
$
|
4,336
|
|
|
$
|
—
|
|
|
$
|
4,336
|
|
Derivative deferred premiums - liability
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,449
|
|
|
$
|
5,449
|
|
15
A summary of the changes in Level 3 fair value measurements for the periods presented are as follows:
|
|
Nine Months Ended
|
|
|
Year Ended
|
|
|
|
September 30, 2017
|
|
|
December 31, 2016
|
|
|
|
(in thousands)
|
|
Balance of Level 3 at beginning of period
|
|
$
|
(5,449
|
)
|
|
$
|
(9,973
|
)
|
Derivative deferred premiums - purchases
|
|
|
—
|
|
|
|
(516
|
)
|
Derivative deferred premiums - settlements
|
|
|
5,009
|
|
|
|
5,040
|
|
Balance of Level 3 at end of period
|
|
$
|
(440
|
)
|
|
$
|
(5,449
|
)
|
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 the Partnership’s 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%. We believe this rate 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 an asset 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 loss is recognized for the difference between the estimated fair value and the carrying value of the assets. For the three months ended September 30, 2017, we recorded non-cash impairment expense of approximately $4.9 million primarily on one of our Permian projects where late-stage waterflood efforts in select wells in the field have longer than anticipated response times to injection. The majority of the non-cash impairment expense of approximately $22.5 million
f
or the nine months ended September 30, 2017, was due to margin compression over the reserve life caused by lower future oil pricing and a higher cost profile on one of our Northeastern Oklahoma projects.
There were no impairment charges for the three months ended September 30, 2016.
For the nine months ended September 30, 2016, we recorded non-cash impairment expense of approximately $0.9 million in our Permian core area due to a revision of reserve estimates at one property. These impairment expenses are included in “Impairment of proved oil and natural gas properties” in our unaudited condensed consolidated statements of operations.
There were no impairment charges related to assets held for sale for the three months ended September 30, 2016. For the nine months ended September 30, 2016, we recorded non-cash impairment expense of approximately $3.6 million related to the Hugoton divestiture to reduce the carrying amount of those assets to their fair value. These assets and liabilities were deemed to meet held for sale accounting criteria as of June 30, 2016, accordingly, the impairment is included in “Impairment of proved oil and natural gas properties sold” in our consolidated statements of operations.
16
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 September 30, 2017, and December 31, 2016, 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:
|
|
Nine Months Ended
|
|
|
Year Ended
|
|
|
|
September 30, 2017
|
|
|
December 31, 2016
|
|
|
|
(in thousands)
|
|
Asset retirement obligations - beginning of period
|
|
$
|
11,331
|
|
|
$
|
12,679
|
|
Liabilities incurred for new wells and interest
|
|
|
759
|
|
|
|
747
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
(17
|
)
|
|
|
—
|
|
Liabilities removed upon sale of wells
|
|
|
—
|
|
|
|
(2,827
|
)
|
Revision of estimates
|
|
|
(75
|
)
|
|
|
155
|
|
Accretion expense
|
|
|
386
|
|
|
|
577
|
|
Asset retirement obligations - end of period
|
|
$
|
12,384
|
|
|
$
|
11,331
|
|
Note 7. Debt
We had outstanding borrowings under our revolving credit facility of $122.0 million at September 30, 2017, and December 31, 2016, respectively. Our current revolving credit facility matures in November 2018.
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.
Borrowings under the revolving credit facility bear 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 1.00% 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 2.00% to 3.75% per annum according to the borrowing base usage. For the three months ended September 30, 2017, the average effective rate was approximately
4.02%
. Any unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base 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, leverage ratios and restrictions on certain transactions and payments, including distributions.
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.
17
At
the quarter ended September 30, 2017, we were
not in compliance with our leverage calculation ratio. On November 10, 2017, the Partnership received a waiver from the Administrative Agent and the Lenders of our revolving credit facility waiving the noncompliance through the earlier of (a) December 15,
2017, or (b) the termination, for any reason, of the Purchase and Sale Agreement (the “Sale Agreement”), dated November 8, 2017, governing the sale of certain oil and gas properties located in Carter and Love Counties, Oklahoma
(
the
“Southern Oklahoma dive
stiture”)
. We believe it is probable that we will cure the violation of the leverage calculation ratio by the en
d of the wavier
period
.
Additionally
, in conjunction with its f
all 2017 borrowing base redetermination, the Partnership is in advance
d
discussions with its lenders to extend the credit facility subject to the satisfaction of certain conditions i
ncluding the Southern Oklahoma d
ivestiture (the “Extension”).
If the transactions contemplated by the Sale Agreement and the Extension are not timely completed, and we are unable to negotiate an additional waiver of the leverage calculation ratio with the Administrative Agent and the Lenders of our revolving credit facility, we may be deemed in default of the revolving credit facility. In that case, unless we are able to secure another form of financing, our lenders would be entitled to accelerate the amounts owed under the revolving credit facility or foreclose on our oil and natural gas properties, either of which would have a material effect on our business and financial condition.
During the spring 2016 semi-annual redetermination and amendment to the credit agreement completed in May 2016, the effective borrowing base as of June 1, 2016, was reduced to $163.0 million and was comprised of a $110.0 million conforming tranche and a permitted overadvance of $53.0 million. The permitted overadvance was scheduled to mature on November 1, 2016.
During August 2016, we completed a non-scheduled redetermination and amendment to the credit agreement in conjunction with our Permian Bolt-On acquisition. Among other changes, this amendment to the credit agreement increased the conforming borrowing base of the Partnership’s revolving credit facility to $140.0 million as of August 11, 2016, modified the definition of “Indebtedness” to exclude the Class A Preferred Units and modified the limitations on restricted payments to specifically provide for the payment of cash distributions on the Class A Preferred Units. The amendment also required that by August 18, 2016, we enter into commodity derivative contracts of not less than 75% of our 2017 projected monthly production and not less than 50% of our 2018 projected monthly production, calculated based on proved developed producing reserves at the time of the agreement. These requirements were satisfied with the execution of additional commodity derivative contracts maturing in 2018. The amendment also required that within 30 days we extend our collateral coverage to include the reserves acquired in the Permian Bolt-On acquisition.
During the fall 2016 semi-annual borrowing base redetermination of our revolving credit facility completed in October 2016, the lender group reaffirmed the existing conforming borrowing base of $140.0 million effective October 28, 2016. There were no changes to the terms or conditions of the credit agreement.
During the spring 2017 semi-annual borrowing base redetermination of our revolving credit facility completed in May 2017, the lender group reaffirmed the Partnership’s $140.0 million conforming borrowing base effective May 24, 2017. There were no changes to the terms or conditions of the credit agreement.
Note 8. Commitments and Contingencies
Leases
We lease corporate office space in Tulsa, Oklahoma and Abilene, Texas. We were also allocated office rent from Mid-Con Energy Operating through August 2016 for office space in Dallas, Texas. Total lease expenses were approximately
$0.1 million
each for the three months ended September 30, 2017, and 2016, and approximately $0.2 million and $0.3 million each for the nine months ended September 30, 2017, and 2016, respectively. These expenses are included in G&A in our unaudited condensed consolidated statements of operations.
Future minimum lease payments under the non-cancellable operating leases are presented in the following table (in thousands):
Remaining 2017
|
|
$
|
122
|
|
2018
|
|
|
490
|
|
2019
|
|
|
413
|
|
2020
|
|
|
418
|
|
2021
|
|
|
423
|
|
Total
|
|
$
|
1,866
|
|
18
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 at least 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 agreement stipulates 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 $0.6 million, including the value of vesting of any outstanding units.
Legal
We are party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management and our General Counsel, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our financial position, results of operations or cash flows.
Note 9. Equity
Common Units
At September 30, 2017, and December 31, 2016, the Partnership’s equity consisted of
30,091,463
and 29,912,230 common units, respectively, representing approximately 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 Class A Preferred Units purchase agreement described below, the Partnership suspended sales of common units pursuant to the Equity Distribution Agreement effective as of the closing date of the issuance of the Class A Preferred Units until the fifth anniversary thereof, unless the Partnership obtains the consent of a majority of the holders of the outstanding Class A 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. 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.
As of September 30, 2017, 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 and also prohibits us from making common unit cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution. 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.
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 (the “Class A Unit Purchase Price”). Proceeds from this issuance were used to fund the Permian Bolt-On acquisition and for general partnership
19
purposes, including the reduction of borrowings under our revolving credit facility. We received net
proceeds of approximately $24.6 million (net of issuance costs of approximately $0.4 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
(approximately $18.6 million) and the beneficial conversion feature (approximately $6.0 million). A beneficial conversion feature is defined as a non-detachable conversion feature that is in the money at the commitment date. Per accounting guidance, we are
required to allocate a portion of the proceeds from the
Class A
Preferred Units to the 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 d
ifference 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 A
Preferred Units.
We record the accretion attributed to the beneficial conversion feature as a deemed distribution using the effective interest method over the five year period prior to the effective date of the holders conversion right. Accretion of the beneficial convers
ion feature was approximately $0.
3
million
and approximately
$0.8
million for the
three and nine months ended September 30, 2017
, respectively
. Accretion of the beneficial conversion feature was approximately $0.
2
million for the three and nine months ende
d September 30, 2016
.
The holders of our Class A 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 the Class A Preferred Units a cumulative, quarterly cash distribution on all Class A 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 Class A Preferred Units, in kind (additional Class A 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. As of September 30, 2017, all Class A Preferred Unit distributions have been paid in cash. No payment or distribution on common units for any quarter is permitted prior to the payment in full of the Class A Preferred Units distribution (including any outstanding arrearages). At September 30, 2017, the Partnership had accrued approximately $0.5 million for the third quarter 2017 distributions that will be paid in cash in December 2017, subsequent to the close of the Southern Oklahoma divestiture.
The following table summarizes cash distributions paid on our Class A Preferred Units during the nine months ended September 30, 2017:
Date Paid
|
|
Period Covered
|
|
Distribution per
Unit
|
|
|
Total Distributions
(in thousands)
|
|
February 14, 2017
|
|
October 1, 2016 - December 31, 2016
|
|
$
|
0.043
|
|
|
$
|
500
|
|
May 15, 2017
|
|
January 1, 2017 - March 31, 2017
|
|
$
|
0.043
|
|
|
$
|
500
|
|
August 14, 2017
|
|
April 1, 2017 - June 30, 2017
|
|
$
|
0.043
|
|
|
$
|
500
|
|
Prior to the five year anniversary of the closing date, each holder of the Class A Preferred Units has the right, subject to certain conditions, to convert all or a portion of their Class A 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 Class A Preferred Units, the Partnership will pay any distributions (to the extent accrued and unpaid as of the then most recent Class A Preferred Units distribution date) on the converted units in cash.
Under the registration rights agreements entered into in connection with the Class A Preferred Units issuance, we were required to use reasonable best efforts to file, within 90 days of the closing date, a registration statement registering resales of common units issued or to be issued upon conversion of the Class A Preferred Units and have the registration statement declared effective within 180 days after the closing date. On June 14, 2017, the previously filed shelf registration statement on Form S-3 was declared effective by the SEC.
Allocation of Net Income (Loss)
Net income (loss), net of distributions on the Class A Preferred Units and amortization of the Class A Preferred Unit’s beneficial conversion feature (see Class A Preferred Units section), is allocated between our general partner and the limited partner unitholders in proportion to their pro rata ownership (exclusive of the Class A Preferred Units limited partnership interest) during the period. The allocation of net income (loss) is presented in our unaudited condensed consolidated statements of operations. 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 Class A Preferred Units.
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 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 management, 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 services for us or on our behalf and other expenses allocated 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, various third parties with an ownership interest in the same property and our affiliate, Mid-Con Energy Operating, are parties to standard oil and natural gas joint operating agreements, pursuant to which we and those third parties pay Mid-Con Energy Operating overhead associated with operating our properties. We and those third parties also pay Mid-Con Energy Operating for its direct and indirect expenses that are chargeable to the wells under their respective operating agreements. The majority of these expenses are included in lease operating expenses (“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.
The following table summarizes the affiliates’ transactions for the periods indicated:
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
|
|
(in thousands)
|
|
Amounts paid for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Services agreement
|
|
$
|
610
|
|
|
$
|
914
|
|
|
$
|
1,903
|
|
|
$
|
2,440
|
|
Operating agreements
|
|
|
1,678
|
|
|
|
1,509
|
|
|
|
4,694
|
|
|
|
4,790
|
|
Oilfield services
|
|
|
809
|
|
|
|
778
|
|
|
|
2,476
|
|
|
|
2,274
|
|
|
|
$
|
3,097
|
|
|
$
|
3,201
|
|
|
$
|
9,073
|
|
|
$
|
9,504
|
|
At September 30, 2017, we had a payable to our affiliate, Mid-Con Energy Operating, of approximately $3.8 million, comprised of a joint interest billing payable of approximately $3.6 million and a payable for operating services of approximately $0.2 million. At December 31, 2016, we had a payable to our affiliate, Mid-Con Energy Operating, of approximately $3.4 million, comprised of a joint interest billing payable of approximately $2.8 million and a payable for operating services of approximately $0.6 million. These amounts were included in accounts payable-related parties in our unaudited condensed consolidated balance sheets.
Note 11. New Accounting Standards
In May 2014, the Financial Accounting Standards Board (“FASB”) issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605,
Revenue Recognition,
and industry-specific guidance in Subtopic 932-605,
Extractive Activities-Oil and Gas-Revenue Recognition
. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that
21
reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative i
nformation of an entity’s nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract a
nd all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard
is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual
financial statement line items. In March, April, May and December 2016, the FASB issued ne
w guidance in Topic 606,
Revenue from Contracts with Customers
, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the id
entification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, non-cash consideration and completed contract modifications at tra
nsition.
This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We plan to adopt
this standard
effective January 1, 2018, using the modified retrospective approach
whereby we will record the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, as an adjustment to opening retained earnings. We have completed our initial assessment and concluded that our revenue recognition
under the new guidance will not materially differ from our current revenue recognition practice. Therefore, we do not expect a cumulative effect adjustment to opening retained earnings.
We are still
evaluating the impact this guidance will have on our pro
cesses and internal controls.
In February 2016, the FASB issued ASU No. 2016-02, “
Leases
(Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. We plan to adopt this standard on January 1, 2019 and believe the primary impact of adoption will be the recognition of assets and liabilities on our balance sheet for current operating leases. We are still evaluating the impact of this standard.
In August, 2016, the FASB issued ASU No. 2016-15,
Classification of Certain Cash Receipts and Cash Payments
(a consensus of the Emerging Issues Task Force). The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities that are required to present a statement of cash flows under FASB Accounting Standards Codification (FASB ASC) 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption during an interim period. We plan to adopt this standard on January 1, 2018. Based on our initial evaluation, we do not anticipate a material impact to our consolidated financial statements upon adoption of this standard.
In January 2017, the FASB issued ASU No. 2017-01, “
Business Combinations
(Topic 805),” with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as asset acquisitions or as business combinations. The amendments in this update provide 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. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output and remove the evaluation of whether a market participant could replace missing elements. This new guidance is effective for annual periods beginning after December 15, 2017, and early adoption is allowed. We are evaluating the impact it will have on our consolidated financial statements.
Note 12. Subsequent Events
Distributions
The Board declared a Class A Preferred Unit distribution for the third quarter of 2017, according to terms outlined in the Partnership Agreement. A cash distribution of $0.043 per Class A Preferred Unit, or approximately $0.5 million in aggregate, will be paid in December 2017 to holders of record subsequent to the close of the Southern Oklahoma divestiture.
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Departure of Officer
On November 6, 2017, Mr. Matthew R. Lewis informed the Board of his resignation as Vice President and Chief Financial Officer of the General Partner to pursue other opportunities. Subsequent to Mr. Lewis’ departure, his duties and responsibilities will be assumed by other members of the management team. Mr. Lewis did not resign due to any disagreement with the Partnership or any matter relating to the Company’s operations, policies or practices. The Partnership did not enter into any agreement with Mr. Lewis as a result of his resignation. Mr. Lewis’ resignation was effective immediately but he will continue to serve in an advisory role until November 30, 2017.
Southern Oklahoma Divestiture
On November 8, 2017, we entered into a definitive purchase and sale agreement to sell oil and natural gas assets within our Southern Oklahoma core area for an aggregate sale price of approximately $25.0 million, subject to customary post-closing sale price adjustments. Per the agreement, the effective date of the sale is October 1, 2017, and the closing date of the divestiture is November 30, 2017. Proceeds from the divestiture will be used to reduce borrowings outstanding under the Partnership’s revolving credit facility.
Class B Convertible Preferred Units
On November 14, 2017, we entered into a definitive agreement to offer up to $15.0 million of Class B Convertible Preferred Units (“Class B Preferred Units”) in a private offering subject to customary closing conditions. The Partnership will use the net proceeds from the offering for general partnership purposes, including but not limited to, future acquisitions and reduction of borrowings outstanding under the Partnership’s revolving credit facility. The Class B Preferred Units will be issued at a price of $1.36 per preferred unit (the “Class B Unit Purchase Price”). The Partnership will pay holders of the Class B Preferred Units a cumulative, quarterly distribution in cash at an annual rate of 8.0%, or under certain circumstances, in additional preferred units, at an annual rate of 10.0%. At any time after the six month anniversary and prior to August 11, 2021, each holder of the preferred units may elect to convert all or any portion of their Class B Preferred Units into common units representing limited partner interests in the Partnership on a one-for-one basis. On August 11, 2021, each holder may elect to cause the Partnership to redeem all or any portion of their Class B Preferred Units for cash at the Class B Unit Purchase Price, and any remaining Class B Preferred Units will thereafter be converted to common units on a one-for-one basis.
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