Note 1. Organization and Nature of Operations
Nature of Operations
Mid-Con Energy Partners, LP ("we," "our," "us," the "Partnership," 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 limited partner units ("common units") are traded 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 included herein have been 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, 2015
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 herein are adequate to make the information not misleading.
The unaudited condensed consolidated financial statements reflect 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 on Form 10-K for the year ended
December 31, 2015
.
All intercompany transactions and account balances have been eliminated.
Reclassifications
The consolidated statements of income for previous periods include certain reclassifications to the other income (expense) accounts that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss).
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,
|
|
2016
|
|
2015
|
|
(in thousands)
|
Non-cash investing information:
|
|
|
|
Change in accrued capital expenditures-oil and natural gas properties
|
513
|
|
|
619
|
|
Change in accrued capital expenditures-other property and equipment
|
(14
|
)
|
|
—
|
|
Tenant improvement allowance deferred-other property and equipment
|
(124
|
)
|
|
—
|
|
Change in accrued receivable-acquisition post-close adjustment
|
419
|
|
|
—
|
|
Change in accrued receivable-divestiture post-close adjustment
|
354
|
|
|
—
|
|
Non-cash financing information:
|
|
|
|
Change in accrued capital expenditures-offering costs
|
(302
|
)
|
|
—
|
|
Supplemental cash flow information:
|
|
|
|
Cash paid for interest
|
5,063
|
|
|
4,606
|
|
Liquidity and Capital Resources
Our ability to finance our operations, fund our capital expenditures and acquisitions, meet or refinance our debt obligations and meet our collateral requirements will depend on our future cash flows. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, oil and natural gas prices, operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. Historically, our primary use of cash has been for debt reduction and to fund capital spending and distributions.
Oil prices fell to 13-year lows during 2016, impacting the way we conduct business. We have implemented a number of adjustments to strengthen our financial position. In January 2015, we restructured a significant portion of our hedge portfolio to limit downside and volatility due to the then prevailing commodity price environment. We have since then entered into additional oil commodity derivative contracts covering a portion of our anticipated oil production through 2019. In the third quarter of 2015, we indefinitely suspended our quarterly cash distributions on common units. We are also aggressively pursuing cost reductions to improve profitability and maximize cash flows. Our primary cost reduction initiatives encompass periodic economic review of each well within our portfolio along with ongoing scrutiny of lease operating expenses and general and administrative expenses.
Our liquidity position at September 30, 2016 consisted of approximately
$2.1 million
of available cash and
$12.1 million
of available borrowings under our revolving credit facility (
$140.0 million
borrowing base less
$127.9 million
of outstanding borrowings). Our borrowing base is redetermined in the spring and fall of each year.
In conjunction with closing the Permian Bolt-On acquisition during the third quarter of 2016, we completed a non-scheduled borrowing base redetermination and executed Amendment No. 10 to the credit agreement on August 11, 2016. As such, our senior lenders unanimously agreed to increase the conforming borrowing base of our revolving credit facility to
$140.0 million
. See Note 7 in this section for additional information regarding our credit facility.
Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures budget, meet our debt service requirements and fund our other commitments and obligations. Although we currently expect our sources of cash to be sufficient to meet our near-term liquidity needs, there can be no assurance that our liquidity requirements will continue to be satisfied given current oil prices and the discretion of our lenders to decrease our borrowing base. Due to the volatility of commodity prices, we may not be able to obtain funding in the equity or capital markets on terms we find acceptable. The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards and reduced and, in some cases, ceased to provide any new funding.
Note 2. Acquisitions and Divestitures
Permian Bolt-On Acquisition
On August 11, 2016, we acquired multiple oil and natural gas properties located in Nolan County, Texas ("Permian Bolt-On") for an aggregate purchase price of approximately
$18.7 million
, after estimated post-closing purchase price adjustments. The Permian Bolt-On acquisition was accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the acquisition 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. The transaction was funded by a private offering of
$25.0 million
Class A Convertible Preferred Units ("Preferred Units"). See Note 9 in this section for additional information regarding the issuance of Preferred Units. The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):
|
|
|
|
|
|
Fair value of net assets:
|
|
|
Oil and natural gas properties
|
|
$
|
19,280
|
|
Total assets acquired
|
|
$
|
19,280
|
|
Fair value of net liabilities assumed:
|
|
|
Asset retirement obligation
|
|
622
|
|
Net assets acquired
|
|
$
|
18,658
|
|
Hugoton Divestiture
On July 28, 2016, we sold our properties located in the Hugoton Basin for proceeds of approximately
$17.9 million
, prior to post-closing adjustments, and recognized a loss of approximately
$0.5 million
which is included as "Loss on sales of oil and natural gas properties, net" in our 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
September 30,
|
|
Nine Months Ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in thousands)
|
Oil and natural gas sales
|
$
|
632
|
|
|
$
|
2,921
|
|
|
$
|
3,602
|
|
|
$
|
9,294
|
|
Expenses
(1)
|
$
|
591
|
|
|
$
|
32,185
|
|
|
$
|
7,717
|
|
|
$
|
39,428
|
|
(1)
Expenses include lease operating expenses, production taxes, accretion, depletion and impairment expenses.
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 the members of our general partner (the "Founders") and approved by the Board of Directors of the general partner. 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 November 20, 2015, the Board of Directors of the general partner approved an amendment to the Long-Term Incentive Program that increased the number of common units available for issuance from
1,764,000
to
3,514,000
.
The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at
September 30, 2016
:
|
|
|
|
|
Number of Common Units
|
Approved and authorized awards
|
3,514,000
|
|
Unrestricted units granted
|
(1,187,306
|
)
|
Restricted units granted, net of forfeitures
|
(400,424
|
)
|
Equity-settled phantom units granted, net of forfeitures
|
(457,500
|
)
|
Awards available for future grant
|
1,468,770
|
|
We recognized
$0.3 million
and
$1.0 million
of total equity-based compensation expense for the three and nine months ended September 30, 2016, respectively, and we recognized
$0.6 million
and
$3.0 million
of total equity-based compensation expense for the three and nine months ended September 30, 2015, respectively. These costs are reported as a component of general and administrative expense in our unaudited condensed consolidated statements of operations.
Unrestricted unit awards
We account for unrestricted awards as equity awards since they are settled by issuing common units. 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. During the nine months ended September 30, 2015, we granted
274,550
unrestricted units with an average grant date fair value of
$4.85
per unit.
Restricted unit awards
We account for restricted awards as equity awards since they will be settled by issuing common units. These units vest over a
two
or
three
year period. The compensation expense we recognize associated with our restricted units is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. We did not issue any restricted units during the nine months ended September 30, 2016. During the nine months ended September 30, 2015, we granted
268,000
restricted units with one-third vesting immediately and the other two-thirds vesting over
two
years, and
26,100
restricted units with a
three
year vesting period.
A summary of our restricted unit awards for the nine months ended
September 30, 2016
is presented below:
|
|
|
|
|
|
|
|
|
Number of Restricted Units
|
|
Average Grant Date Fair Value per Unit
|
Outstanding at December 31, 2015
|
222,833
|
|
|
$
|
8.49
|
|
Units granted
|
—
|
|
|
—
|
|
Units vested
|
(112,478
|
)
|
|
9.16
|
|
Units forfeited
|
(33,433
|
)
|
|
9.69
|
|
Outstanding at September 30, 2016
|
76,922
|
|
|
$
|
5.67
|
|
|
|
|
|
As of
September 30, 2016
, there were approximately
$0.3
million of unrecognized compensation costs related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately
eight months
.
Equity-settled phantom unit awards
We account for equity-settled phantom awards as equity awards since they will be settled by issuing common units. These 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. The compensation expense we recognize associated with our equity-settled phantom units is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. During the nine months ended September 30, 2016, we granted
347,500
equity-settled phantom awards 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. During the nine months ended September 30, 2015, we granted
69,000
equity-settled phantom units with one-third vesting immediately and the other two-thirds vesting over two years and
46,500
equity-settled phantom units with a three year vesting period.
A summary of our equity-settled phantom unit awards for the nine months ended September 30, 2016 is presented below:
|
|
|
|
|
|
|
|
|
Number of Equity-Settled Phantom Units
|
|
Average Grant Date Fair Value per Unit
|
Outstanding at December 31, 2015
|
77,500
|
|
|
$
|
2.81
|
|
Units granted
|
374,500
|
|
|
1.55
|
|
Units vested
|
(146,841
|
)
|
|
2.03
|
|
Units forfeited
|
(17,500
|
)
|
|
2.02
|
|
Outstanding at September 30, 2016
|
287,659
|
|
|
$
|
1.64
|
|
As of
September 30, 2016
, there were approximately
$0.4
million of unrecognized compensation costs related to equity-settled phantom units. The cost is expected to be recognized over a weighted average period of approximately
one year, nine months
.
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. The commodity derivative contracts that we have entered into generally have the effect of providing us with a fixed price or a floor for a portion of our expected future oil production over a fixed period of time. 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 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.
At September 30, 2016, our derivative contracts were in a net liability position with a fair value of approximately
$2.9
million. At December 31, 2015, our derivative contracts were in a net asset position with a fair value of approximately
$25.6
million. All of our commodity derivative contracts are with major financial institutions that are also members of our banking group. 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 September 30, 2016, all of our counterparties have performed pursuant to their commodity derivative contracts.
At September 30, 2016 and December 31, 2015, our commodity derivative contracts had maturities that extended through December 2018 and December 2017, respectively, and were comprised of commodity price swap, call, put and collar contracts.
For commodity price swap contracts, at the time of execution the seller agrees to receive a fixed price at maturity in exchange for any gains or losses that might be realized from allowing the price of the underlying commodity to float with the market until maturity. From the perspective of the seller, these instruments limit exposure to price declines below the price fixed by the swap at the expense of participating in any price increases above the price fixed by the swap.
For commodity price call contracts, in return for a premium received, which can be effected at either execution or settlement, the seller is obliged to pay the difference, when positive, between the market price of the underlying commodity at maturity and the strike price. From the perspective of the seller, these instruments provide income via the premium received at the expense of any incremental gains that would have otherwise been received above the strike price.
For commodity price put contracts, in return for a premium paid, which can be effected at either execution or settlement, the purchaser has the right to receive the difference, when positive, between the strike price and the market price of the underlying commodity at maturity. From the perspective of the purchaser, these instruments limit exposure to price declines below the strike price at the expense of premiums paid.
For commodity price collar contracts, a collar is the combination of a put purchased or sold by a party and a call option sold or purchased by the same party. The collar is defined as costless when the value of the option purchased is approximately offset by the value of the option sold.
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 payments made or received on monthly settlements, proceeds 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
September 30, 2016
, we had the following oil derivatives net positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period Covered
|
Weighted Average Fixed Price
|
|
Weighted Average Floor Price
|
|
Weighted Average Ceiling Price
|
|
Total Bbls
Hedged/day
|
|
NYMEX Index
|
Swaps - 2016
|
$
|
64.18
|
|
|
|
|
|
|
1,304
|
|
|
WTI
|
Puts - 2016
|
|
|
$
|
50.00
|
|
|
$
|
—
|
|
|
1,957
|
|
|
WTI
|
Collars - 2017
|
|
|
$
|
40.00
|
|
|
$
|
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
|
At December 31, 2015, we had the following oil derivatives net positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period Covered
|
Weighted Average Fixed Price
|
|
Weighted Average Floor Price
|
|
Weighted Average Ceiling Price
|
|
Total Bbls
Hedged/day
|
|
NYMEX Index
|
Swaps - 2016
|
$
|
79.98
|
|
|
|
|
|
|
1,598
|
|
|
WTI
|
Collars - 2016
|
|
|
$
|
50.00
|
|
|
$
|
50.00
|
|
|
328
|
|
|
WTI
|
Puts - 2016
|
|
|
$
|
50.00
|
|
|
$
|
—
|
|
|
1,475
|
|
|
WTI
|
Puts - 2017
|
|
|
$
|
50.00
|
|
|
$
|
—
|
|
|
1,932
|
|
|
WTI
|
During the first quarter of 2015, we restructured a significant portion of our existing commodity derivative contracts that were in place at December 31, 2014 and entered into new commodity derivative contracts which extended through September 2016. In connection with the early termination of our commodity derivative contracts, we received net proceeds of approximately
$11.1
million. We received approximately
$5.9
million from selling calls and paid approximately
$19.8
million in premiums to extend the contracts through September 2016. The restructuring also resulted in approximately
$4.1
million of deferred premium put options. As of September 30, 2016, all deferred premiums related to these restructured contracts have been paid.
In connection with the fall 2015 semi-annual redetermination of our borrowing base, we entered into additional commodity derivative contracts resulting in total commodity derivative contracts covering at least
80%
of our 2016 projected monthly production and at least
50%
of our 2017 projected monthly production, calculated based on Proved Developed Producing reserves. No cash settlements were required and the contracts included deferred premiums of approximately
$7.8
million that will be paid through December 2017. As of September 30, 2016, we had paid approximately
$1.6 million
of the deferred premiums in connection with these contract settlements.
In connection with the spring 2016 semi-annual redetermination of our borrowing base, we unwound and early terminated existing hedges covering production from July 2016 through September 2016 and entered into new commodity derivative contracts which extend through June 2018. In connection with the early termination of our commodity derivative contracts, we received proceeds of approximately
$5.8 million
and paid related deferred premiums of approximately
$1.5 million
.
In connection with the non-scheduled redetermination of our borrowing base and Amendment No.10 to our credit agreement executed in August 2016, we entered into new commodity derivative contracts covering at least
75%
of our 2017 projected monthly production and at least
50%
of our 2018 projected monthly production, calculated based on Proved Developed Producing reserves. The new contracts extend through December 2018. No cash settlements were required and the contracts included deferred premiums of approximately
$0.4 million
that will be paid through December 2018.
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, 2016
and December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Amounts
Recognized
|
|
Gross Amounts
Offset in the
Unaudited
Condensed
Consolidated
Balance Sheet
|
|
Net Amounts
Presented in the
Unaudited
Condensed
Consolidated
Balance Sheet
|
|
(in thousands)
|
September 30, 2016:
|
|
|
|
|
|
Assets
|
|
|
|
|
|
Derivative financial instruments - current asset
|
$
|
5,032
|
|
|
$
|
(3,656
|
)
|
|
$
|
1,376
|
|
Derivative financial instruments - long-term asset
|
1,599
|
|
|
(1,599
|
)
|
|
—
|
|
Total
|
$
|
6,631
|
|
|
$
|
(5,255
|
)
|
|
$
|
1,376
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Derivative financial instruments - current liability
|
$
|
(899
|
)
|
|
$
|
(1,408
|
)
|
|
$
|
(2,307
|
)
|
Derivative deferred premium - current liability
|
(5,064
|
)
|
|
5,064
|
|
|
—
|
|
Derivative financial instruments - long-term liability
|
(2,048
|
)
|
|
56
|
|
|
(1,992
|
)
|
Derivative deferred premium - long-term liability
|
(1,543
|
)
|
|
1,543
|
|
|
—
|
|
Total
|
$
|
(9,554
|
)
|
|
$
|
5,255
|
|
|
$
|
(4,299
|
)
|
Net Liability
|
$
|
(2,923
|
)
|
|
$
|
—
|
|
|
$
|
(2,923
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Amounts
Recognized
|
|
Gross Amounts
Offset in the
Unaudited
Condensed
Consolidated
Balance Sheet
|
|
Net Amounts
Presented in the
Unaudited
Condensed
Consolidated
Balance Sheet
|
|
(in thousands)
|
December 31, 2015:
|
|
|
|
|
|
Assets
|
|
|
|
|
|
Derivative financial instruments - current asset
|
$
|
29,973
|
|
|
$
|
(5,554
|
)
|
|
$
|
24,419
|
|
Derivative financial instruments - long-term asset
|
6,077
|
|
|
(4,933
|
)
|
|
1,144
|
|
Total
|
$
|
36,050
|
|
|
$
|
(10,487
|
)
|
|
$
|
25,563
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
Derivative financial instruments - current liability
|
$
|
(514
|
)
|
|
$
|
514
|
|
|
$
|
—
|
|
Derivative deferred premium - current liability
|
(5,040
|
)
|
|
5,040
|
|
|
—
|
|
Derivative deferred premium - long-term liability
|
(4,933
|
)
|
|
4,933
|
|
|
—
|
|
Total
|
$
|
(10,487
|
)
|
|
$
|
10,487
|
|
|
$
|
—
|
|
Net Asset
|
$
|
25,563
|
|
|
$
|
—
|
|
|
$
|
25,563
|
|
The following table presents the impact of derivative financial instruments and their location within the unaudited condensed consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in thousands)
|
Net settlements on matured derivatives
|
$
|
1,182
|
|
|
$
|
8,383
|
|
|
$
|
18,467
|
|
|
$
|
15,566
|
|
Net settlements on early terminations and modifications of derivatives
|
5,820
|
|
|
—
|
|
|
5,820
|
|
|
11,069
|
|
Net change in fair value of derivatives
|
(7,446
|
)
|
|
11,388
|
|
|
(32,251
|
)
|
|
(14,091
|
)
|
Total (loss) gain on derivatives, net
|
$
|
(444
|
)
|
|
$
|
19,771
|
|
|
$
|
(7,964
|
)
|
|
$
|
12,544
|
|
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 Measures 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 and put contracts.
Level 3
—Financial assets and liabilities for which values are based on prices or valuation techniques 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, 2016 and December 31, 2015.
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 changes in valuation techniques or related inputs for the nine months ended September 30, 2016 and for the year ended December 31, 2015.
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. See Note 4 in this section for a summary of our derivative financial instruments.
Assets and Liabilities Measured at Fair Value on a Non-recurring Basis
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.
The estimated fair values of proved oil and natural gas properties assumed 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. The estimated fair values of unevaluated oil and
natural gas properties were based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and natural gas properties assumed is deemed to use Level 3 inputs. See Note 2 in this section for further discussion of the Partnership's acquisitions.
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: (i) reserves; (ii) future operating and developmental costs; (iii) future commodity prices; (iv) a market-based weighted average cost of capital rate; and (v) the rate at which future cash flows are discounted to estimate present value. We discount future values by a per annum rate of
10%
because we believe this amount approximates our long-term cost of capital and accordingly, is well aligned with our internal business decisions. The underlying commodity prices embedded in our estimated cash flows are the product of a process that begins with Level 1 NYMEX-WTI forward curve pricing, as well as Level 3 assumptions including: pricing adjustments for estimated location and quality differentials, production costs, capital expenditures, production volumes, decline rates and estimated reserves. 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 sum of 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. There were no impairment charges for the three months ended September 30, 2016. During the nine months ended September 30, 2016, we recorded a non-cash impairment charge of approximately
$0.9
million resulting from a revision of reserve estimates for a property in our Permian core area. The impairment is included in "Impairment of proved oil and natural gas properties" in our unaudited condensed consolidated statements of operations. During the nine months ended September 30, 2016, we recorded a non-cash impairment charge of approximately
$3.6 million
related to the Hugoton core area 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 unaudited condensed consolidated statements of operations. During the three and nine months ended September 30, 2015, we recorded a non-cash impairment charge of approximately
$40.9
million due to a decline in commodity prices and to a lesser degree, reduced reserve estimates. The impairment charges are included in “Impairment of proved oil and natural gas properties" in our unaudited condensed consolidated statements of operations.
The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value as of
September 30, 2016
and
December 31, 2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Fair Value
|
|
(in thousands)
|
September 30, 2016
|
|
|
|
|
|
|
|
Assets and Liabilities Measured at Fair Value on a Recurring Basis
|
|
|
|
|
|
|
|
Derivative financial instruments - asset
|
$
|
—
|
|
|
$
|
6,631
|
|
|
$
|
—
|
|
|
$
|
6,631
|
|
Derivative financial instruments - liability
|
$
|
—
|
|
|
$
|
2,947
|
|
|
$
|
—
|
|
|
$
|
2,947
|
|
Derivative deferred premiums - liability
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6,607
|
|
|
$
|
6,607
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities Measured at Fair Value on a Non-recurring Basis
|
|
|
|
|
|
|
|
Asset retirement obligations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
714
|
|
|
$
|
714
|
|
Impairment of proved oil and natural gas properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
895
|
|
|
$
|
895
|
|
Impairment of proved oil and natural gas properties sold
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,578
|
|
|
$
|
3,578
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
|
Assets and Liabilities Measured at Fair Value on a Recurring Basis
|
|
|
|
|
|
|
|
Derivative financial instruments - asset
|
$
|
—
|
|
|
$
|
36,050
|
|
|
$
|
—
|
|
|
$
|
36,050
|
|
Derivative financial instruments - liability
|
$
|
—
|
|
|
$
|
514
|
|
|
$
|
—
|
|
|
$
|
514
|
|
Derivative deferred premiums - liability
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,973
|
|
|
$
|
9,973
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities Measured at Fair Value on a Non-recurring Basis
|
|
|
|
|
|
|
|
Asset retirement obligations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,924
|
|
|
$
|
4,924
|
|
Impairment of proved oil and natural gas properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
103,938
|
|
|
$
|
103,938
|
|
A summary of the changes in Level 3 fair value measurements for the periods presented are as follows:
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30, 2016
|
|
Year Ended
December 31, 2015
|
|
(in thousands)
|
Balance of Level 3 at beginning of period
|
$
|
(9,973
|
)
|
|
$
|
—
|
|
Derivative deferred premiums - purchases
|
(400
|
)
|
|
(11,914
|
)
|
Derivative deferred premiums - settlements
|
3,766
|
|
|
1,941
|
|
Balance of Level 3 at end of period
|
$
|
(6,607
|
)
|
|
$
|
(9,973
|
)
|
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 production operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or 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 asset retirement obligations 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. Over time, 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, 2016
and
December 31, 2015
, 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
September 30, 2016
|
|
Year Ended
December 31, 2015
|
|
(in thousands)
|
Asset retirement obligations - beginning of period
|
$
|
12,679
|
|
|
$
|
7,363
|
|
Liabilities incurred for new wells and interest
|
714
|
|
|
42
|
|
Liabilities settled upon plugging and abandoning wells
|
—
|
|
|
(40
|
)
|
Liabilities removed upon sale of wells
|
(2,827
|
)
|
|
—
|
|
Revision of estimates
(1)
|
—
|
|
|
4,882
|
|
Accretion expense
|
443
|
|
|
432
|
|
Asset retirement obligations - end of period
|
$
|
11,009
|
|
|
$
|
12,679
|
|
(1)
The revision of estimates that occurred during the year ended December 31, 2015 was primarily due to a change in estimated plugging and abandonment costs based on 2015 settlements.
Note 7. Debt
A summary of our debt at September 30, 2016 and year ended December 31, 2015 is presented below:
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30, 2016
|
|
Year Ended
December 31, 2015
|
|
(in thousands)
|
Revolving credit facility
|
$
|
127,900
|
|
|
$
|
180,000
|
|
Less: current portion
|
—
|
|
|
30,000
|
|
Total long-term debt
|
$
|
127,900
|
|
|
$
|
150,000
|
|
At September 30, 2016, we had
$127.9 million
of borrowings outstanding under our revolving credit facility that 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 matters that may vary. 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 lender, 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: (i) the greater of the prime rate of the 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 (ii) 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, 2016, the average effective rate was approximately
3.74%
. 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, 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. We were in compliance with these covenants as of and during the nine months ended September 30, 2016.
During February 2015, the revolving credit facility was amended to allow our Consolidated EBITDAX calculation, as defined in section 7.13 of the original revolving credit agreement, to reflect the net cash flows attributable to the restructured commodity derivative contracts that occurred during January 2015 for the periods of the first quarter 2015 through the third quarter of 2016.
During the spring 2015 semi-annual redetermination and amendment to the credit agreement completed in April 2015, the borrowing base under the revolving credit facility was reduced to
$220.0
million from
$240.0
million. No other material terms of the original credit agreement were amended.
During the fall 2015 semi-annual redetermination and amendment to the credit agreement completed in November 2015, the borrowing base under the underlying revolving credit facility was reduced to
$190.0
million from
$220.0 million
, consisting of a
$165.0
million conforming tranche, which required six monthly commitment reductions of
$2.5
million each through May 2016, and a
$25.0
million non-conforming tranche that matured on May 1, 2016. The credit facility amendment also designated Wells Fargo Bank, National Association, as our administrative and collateral agent, replacing Royal Bank of Canada. This redetermination also required that by December 10, 2015 we enter into commodity derivative contracts of not less than
80%
of our 2016 projected monthly production and not less than
50%
of our 2017 projected monthly production, calculated based on Proved Developed Producing reserves at the time of the agreement. These requirements were satisfied during November 2015 with the execution of additional commodity derivative contracts maturing in 2016 and 2017. In connection with this amendment to our revolving credit facility, we incurred financing fees and expenses of approximately
$0.7
million, which will be amortized over the remaining life of the revolving credit facility. Such amortized expenses are recorded as "interest expense" in our unaudited condensed consolidated statements of operations.
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. In addition, the amendment (i) required the Partnership to provide a monthly excess cash flow report; (ii) required the Partnership to make varied minimum monthly principal payments totaling approximately
$1.9 million
through October 31, 2016; (iii) reduced the conforming borrowing base to
$105.0 million
upon the close of the previously announced Hugoton divestiture; (iv) allowed an additional non-scheduled borrowing base redetermination between September 1, 2016 and November 1, 2016 to be requested by any lender; (v) increased the minimum collateral coverage from
90%
to
95%
of proved reserves (and
100%
of PDP reserves); (vi) required the Partnership to unwind and early terminate existing hedges covering production from July 2016 through September 2016 and add new at-the-market swap contracts to replace these hedge terminations; and (vii) required the net proceeds from the previously announced Hugoton sale and from the early termination of hedge contracts to be applied to debt reduction.
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, the 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 Preferred Units and modified the limitations on restricted payments to specifically provide for the payment of cash distributions on the 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.
Note 8. Commitments and Contingencies
We lease corporate office space in Tulsa, Oklahoma and Abilene, Texas. We are also allocated office rent from Mid-Con Energy Operating. Total lease expenses were approximately
$0.1 million
each for the three months ended September 30, 2016 and 2015, and approximately
$0.3 million
each for the nine months ended September 30, 2016 and 2015, respectively. These expenses are included in general and administrative expenses in our unaudited condensed consolidated statements of operations.
Future minimum lease payments under the non-cancellable operating leases at September 30, 2016 were as follows (in thousands):
|
|
|
|
|
Remaining 2016
|
$
|
122
|
|
2017
|
490
|
|
2018
|
490
|
|
2019
|
413
|
|
2020
|
418
|
|
2021
|
423
|
|
Total
|
$
|
2,356
|
|
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.
Our general partner has entered into employment agreements with the following named employees of our general partner: Jeffrey R. Olmstead, President and Chief Executive Officer, and Charles R. Olmstead, Executive Chairman of the Board. The employment agreements automatically renew for one-year terms unless either we or the employee gives written notice of termination by at least February1st preceding any such August 1st. 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 of Directors of our general partner 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
$0.7
million, including the value of vesting of any outstanding units.
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, 2016
and
December 31, 2015
, the Partnership’s equity consisted of
29,912,230
and
29,724,890
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 Convertible Preferred Units agreement described below, the Partnership suspended the Equity Distribution Agreement effective as of the closing date until the fifth anniversary of the closing date of the Preferred Units purchase agreement, or the consent of a majority of the holders of the outstanding Preferred Units.
Class A Convertible Preferred Units
On August 11, 2016, we completed our previously announced private placement of
11,627,906
Class A Convertible Preferred Units for an aggregate offering price of
$25.0 million
. The Preferred Units were issued at a price of
$2.15
per preferred unit (the "Unit Purchase Price"). Proceeds from this issuance were used to fund the Permian Bolt-On acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility.
We will pay holders of the Preferred Units a cumulative, quarterly distribution on all Preferred Units then outstanding (i) in cash at an annual rate of
8.0%
, or (ii) 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 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.
At any time after the six-month anniversary and prior to the
five
year anniversary of the closing date, each holder of the Preferred Units shall have 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; provided that any holder electing conversion requests the conversion of at least the lesser of (i)
100%
of such holder's remaining Preferred Units or (ii)
$1,000,000
of Preferred Units, based on the Unit Purchase Price. On the fifth anniversary of the closing date of the offering, each holder shall have the right to cause the Partnership to redeem all or any portion of their Preferred Units for cash at the Unit Purchase Price, and any remaining Preferred Units will thereafter be converted to common units on a one-for-one basis, subject to adjustment for splits, reverse splits, subdivisions, combinations and reclassifications of the common units. Upon conversion of 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.
Upon a change of control, each holder will have the right, at its election, to either (i) if the Partnership is the surviving entity of such change of control, continue to hold Preferred Units; or (ii) convert all or any portion of the Preferred Units held by such holder into common units on a one-for-one basis, subject to adjustments for splits, reverse splits, subdivisions, combinations and reclassifications. If any Preferred Units remain outstanding following a change of control in which the Partnership is not the surviving entity, then immediately following effectiveness of such change of control, the Partnership shall redeem in cash all, but not less than all, of the outstanding Preferred Units at a price per Preferred Unit equal to the Unit Purchase Price multiplied by the change of control redemption multiple then in effect.
Under the registration rights agreements, we are 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 Preferred Units and have the registration statement declared effective within
180 days
after the closing date. We are required to use reasonable best efforts to continue to maintain the effectiveness of the registration statement until all securities have been sold or the third anniversary of the effectiveness deadline. In addition, from and after the first anniversary of the closing date, holders of an aggregate of at least
$1,000,000
of Preferred Units (based on the Unit Purchase Price) shall have piggyback registration rights on all Partnership registrations, subject to customary carve backs, and holders of an aggregate of at least
$5,000,000
of Preferred Units (based on the Unit Purchase Price) shall have demand registration rights; provided that the holders shall be entitled to a demand registration right not more frequently that once during any twelve month period.
In the event of any liquidation, dissolution or winding-up of the Partnership, each preferred unit will receive in preference to the holders of all existing classes or series of equity securities of the Partnership a per unit amount equal to the Unit Purchase Price (subject to any customary anti-dilution adjustments), plus all accrued and unpaid distributions on such Preferred Units (the "liquidation preference").
The Preferred Unit purchase agreement also requires the Partnership to suspend sales of common units pursuant to the Equity Distribution Agreement from the closing date through the fifth anniversary of the closing date and prohibits the Partnership from incurring any indebtedness (other than under the Partnership’s existing revolving credit facility and trade accounts payable arising in the ordinary course of business) without the consent of the majority of the holders of the Preferred Units.
We received net proceeds of approximately
$24.7 million
(net of issuance costs of approximately
$0.3 million
) in connection with the issuance of Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Preferred Units (approximately
$18.7 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 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 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 Preferred Units. We will record the accretion attributed to the beneficial conversion feature as a deemed distribution using the straight line method over the five year period prior to the effective date of the holders conversion right. Accretion of the beneficial conversion feature was approximately
$0.2 million
for the three months ended September 30, 2016.
Our Distributions
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 the future cash distributions since they are dependent upon our projections for future earnings, cash flows, capital requirements, financial conditions and other factors.
Preferred Unit holders will receive quarterly distributions in cash at an annual rate of
8.0%
or, under certain circumstances, in additional Preferred Units at an annual rate of
10.0%
. The holders of the 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. No payment or distribution on common units for any quarter is permitted prior to the payment in full of the Preferred Units distribution (including any outstanding arrearages). As announced on October 27, 2016, the Board of Directors of the general partner declared a distribution for the period from August 11, 2016 to September 30, 2016 of approximately
$0.3 million
to be paid on November 14, 2016 to holders of record as of the close of business on November 7, 2016.
As of September 30, 2016, cash distributions to our common units continue 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 of Directors 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.
Allocation of Net Income or Loss
Net income or loss, net of distributions on the Preferred Units and amortization of the preferred unit beneficial conversion feature (see Class A Convertible Preferred Units section), is allocated between our general partner and the limited partner unitholders in proportion to their pro rata ownership (exclusive of the Preferred Units limited partnership interest) during the period. The allocation of net income or loss is presented in our unaudited condensed consolidated statements of operations.
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 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 general and administrative expenses 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 party to standard oil and natural gas joint operating agreements, pursuant to which we and those third parties pay Mid-Con Energy Operating overhead charges associated with operating our properties. We and those third parties 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 in our unaudited condensed consolidated statements of operations.
Oilfield Services
. We are party to operating agreements, pursuant to which Mid-Con Energy Operating bills us for oilfield services performed by our affiliate ME3 Oilfield Service. These amounts are either included in lease operating expenses 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
September 30,
|
|
Nine Months Ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Amounts paid for:
|
(in thousands)
|
Services agreement
|
$
|
914
|
|
|
$
|
998
|
|
|
$
|
2,440
|
|
|
$
|
2,676
|
|
Operating agreements
|
1,509
|
|
|
2,067
|
|
|
4,790
|
|
|
6,225
|
|
Oilfield services
|
778
|
|
|
764
|
|
|
2,274
|
|
|
2,677
|
|
|
$
|
3,201
|
|
|
$
|
3,829
|
|
|
$
|
9,504
|
|
|
$
|
11,578
|
|
At
September 30, 2016
and December 31, 2015, we had net payables to Mid-Con Energy Operating of approximately
$0.1 million
and
$0.5 million
, respectively, which 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 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 information 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 and 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. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Partnership is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15,
Presentation of Financial Statements - Going Concern
(Subtopic 205-40)
: Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern.
The amendments in ASU 2014-15 are intended to define management's responsibility to evaluate whether there is a substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This standard is effective for the annual periods ending after December 15, 2016, and for interim periods within annual period beginning after December 15, 2016. Early adoption is permitted. As of September 30, 2016, the Partnership has not elected early adoption.
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. As of September 30, 2016, the Partnership has not elected early adoption.
In March 2016, the FASB issued Accounting Standards Update No. 2016-09,
Improvements to Employee Share-Based Payment Accounting.
The guidance simplifies the accounting for employee stock-based payment transactions including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification of awards as either equity or liabilities, and classification of related amounts within the statement of cash flows. The guidance requires the recognition of the income tax effects of awards in the income statement when the awards vest or are settled, thus eliminating additional paid in capital pools. The guidance also allows for the employer to repurchase more of an employee’s shares for tax withholding purposes without triggering liability accounting. In addition, the guidance allows for a policy election to account for forfeitures as they occur rather than on an estimated basis. The guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and early adoption is permitted. As of September 30, 2016, the Partnership has not elected early adoption.
In August, 2016, the FASB issued Accounting Standards Update 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. As of September 30, 2016, the Partnership has not yet adopted this update and is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.
Note 12. Subsequent Events
Class A Convertible Preferred Units
As announced on October 27, 2016, the Board of Directors of the general partner declared a distribution for the period from August 11, 2016 to September 30, 2016 of approximately
$0.3 million
to be paid on November 14, 2016 to holders of record as of the close of business on November 7, 2016.
Fall 2016 Borrowing Base Redetermination
On October 28, 2016, the Partnership completed its fall 2016 semi-annual borrowing base redetermination under its reserve based revolving credit facility. The lender group agreed to reaffirm the previously 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. The next regularly scheduled borrowing base redetermination will occur on or about May 1, 2017.