Results of Operations by Segment
Midstream Operating Results
The following table sets forth the selected financial and operating data pertaining to the Midstream segment for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
December 31,
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Variance
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation sales
|
|
$
|
6,825
|
|
$
|
6,651
|
|
$
|
174
|
|
3%
|
Gathering and transportation lease revenues
|
|
|
59,090
|
|
|
53,025
|
|
|
6,065
|
|
11%
|
Total gathering and transportation sales
|
|
|
65,915
|
|
|
59,676
|
|
|
6,239
|
|
10%
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
1,499
|
|
|
1,145
|
|
|
354
|
|
31%
|
Transportation operating expenses
|
|
|
11,553
|
|
|
12,316
|
|
|
(763)
|
|
(6%)
|
Depreciation and amortization
|
|
|
21,391
|
|
|
21,189
|
|
|
202
|
|
1%
|
Asset impairments
|
|
|
32,119
|
|
|
—
|
|
|
32,119
|
|
NM (a)
|
Accretion expense
|
|
|
326
|
|
|
299
|
|
|
27
|
|
9%
|
Total operating expenses
|
|
|
66,888
|
|
|
34,949
|
|
|
31,939
|
|
91%
|
Other income:
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from equity investments
|
|
|
2,831
|
|
|
12,859
|
|
|
(10,028)
|
|
(78%)
|
Operating income
|
|
$
|
1,858
|
|
$
|
37,586
|
|
$
|
(35,728)
|
|
(95%)
|
|
(a)
|
|
Variances deemed to be Not Meaningful “NM.”
|
Gathering and transportation sales. Gathering and transportation sales increased by approximately $0.2 million to approximately $6.8 million for the year ended December 31, 2019, compared to approximately $6.7 million during the same period in 2018.
Gathering and transportation lease revenues. Gathering and transportation lease revenues increased by approximately $6.1 million, or 11%, to approximately $59.1 million for the year ended December 31, 2019, compared to approximately $53.0 million during the same period in 2018. This increase was primarily the result of an increase in the rate charged for natural gas transported on Western Catarina Midstream that was produced from outside the dedicated acreage under the Gathering Agreement.
Lease operating expenses. Lease operating expenses, which include ad valorem taxes, increased approximately $0.4 million, or 31%, to approximately $1.5 million for the year ended December 31, 2019, compared to approximately $1.1 million during the same period in 2018.
Transportation operating expenses. Our transportation operating expenses generally consist of gathering and transportation operating expenses, labor, vehicles, supervision, minor maintenance, tools, supplies, and integrity management expenses. Our transportation operating expense decreased approximately $0.8 million, or 6%, to approximately $11.6 million for the year ended December 31, 2019, compared to approximately $12.3 million during the same period in 2018.
Depreciation and amortization expense. Gathering and transportation assets are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 5 to 15 years for equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets. Our depreciation and amortization expense increased approximately $0.2 million, or 1%, to approximately $21.4 million for the year ended December 31, 2019, compared to approximately $21.2 million during the same period in 2018.
Impairment expense. For the year ended December 31, 2019, our non-cash impairment charge was approximately $32.1 million, to impair the Seco Pipeline. We received a written notice from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective as of February 12, 2020. See Note 21 “Subsequent Events” of our Notes to
Consolidated Financial Statements for additional information on the termination of the Seco Pipeline Transportation Agreement. We did not record impairment on our gathering and transportation assets during the year ended December 31, 2018.
Earnings from equity investments. Earnings from equity investments decreased approximately $10.0 million, or 78%, to approximately $2.8 million for the year ended December 31, 2019, compared to approximately $12.9 million for the same period in 2018. This decrease in earnings was primarily the result of lower throughput during the year ended December 31, 2019.
Production Operating Results
The following tables set forth the selected financial and operating data pertaining to the Production segment for the periods indicated (in thousands, except net production and average sales and costs):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
December 31,
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Variance
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales at market price
|
|
$
|
424
|
|
$
|
1,037
|
|
$
|
(613)
|
|
(59%)
|
Natural gas hedge settlements
|
|
|
94
|
|
|
(37)
|
|
|
131
|
|
NM (a)
|
Natural gas mark-to-market activities
|
|
|
165
|
|
|
(47)
|
|
|
212
|
|
NM (a)
|
Natural gas total
|
|
|
683
|
|
|
953
|
|
|
(270)
|
|
(28%)
|
Oil sales
|
|
|
13,543
|
|
|
19,872
|
|
|
(6,329)
|
|
(32%)
|
Oil hedge settlements
|
|
|
807
|
|
|
(1,330)
|
|
|
2,137
|
|
NM (a)
|
Oil mark-to-market activities
|
|
|
(4,838)
|
|
|
2,730
|
|
|
(7,568)
|
|
NM (a)
|
Oil total
|
|
|
9,512
|
|
|
21,272
|
|
|
(11,760)
|
|
(55%)
|
NGL sales
|
|
|
539
|
|
|
1,709
|
|
|
(1,170)
|
|
(68%)
|
Total revenues
|
|
|
10,734
|
|
|
23,934
|
|
|
(13,200)
|
|
(55%)
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
5,879
|
|
|
6,719
|
|
|
(840)
|
|
(13%)
|
Production taxes
|
|
|
621
|
|
|
1,104
|
|
|
(483)
|
|
(44%)
|
Gain on sale of assets
|
|
|
—
|
|
|
(3,186)
|
|
|
3,186
|
|
NM (a)
|
Depreciation, depletion and amortization
|
|
|
3,942
|
|
|
4,798
|
|
|
(856)
|
|
(18%)
|
Accretion expense
|
|
|
200
|
|
|
198
|
|
|
2
|
|
1%
|
Total operating expenses
|
|
|
10,642
|
|
|
9,633
|
|
|
1,009
|
|
10%
|
Operating income
|
|
$
|
92
|
|
$
|
14,301
|
|
$
|
(14,209)
|
|
(99%)
|
|
(a)
|
|
Variances deemed to be Not Meaningful “NM.”
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
December 31,
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Variance
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
231
|
|
|
434
|
|
|
(203)
|
|
(47%)
|
Oil production (MBbl)
|
|
|
228
|
|
|
296
|
|
|
(68)
|
|
(23%)
|
NGLs (MBbl)
|
|
|
42
|
|
|
71
|
|
|
(29)
|
|
(41%)
|
Total production (MBoe)
|
|
|
309
|
|
|
439
|
|
|
(130)
|
|
(30%)
|
Average daily production (Boe/d)
|
|
|
847
|
|
|
1,203
|
|
|
(356)
|
|
(30%)
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price per Mcf with hedge settlements
|
|
$
|
2.24
|
|
$
|
2.30
|
|
$
|
(0.06)
|
|
(3%)
|
Natural gas price per Mcf without hedge settlements
|
|
$
|
1.84
|
|
$
|
2.39
|
|
$
|
(0.55)
|
|
(23%)
|
Oil price per Bbl with hedge settlements
|
|
$
|
62.94
|
|
$
|
62.64
|
|
$
|
0.30
|
|
0%
|
Oil price per Bbl without hedge settlements
|
|
$
|
59.40
|
|
$
|
67.14
|
|
$
|
(7.74)
|
|
(12%)
|
NGL price per Bbl without hedge settlements
|
|
$
|
12.83
|
|
$
|
24.07
|
|
$
|
(11.24)
|
|
(47%)
|
Total price per Boe with hedge settlements
|
|
$
|
49.86
|
|
$
|
48.41
|
|
$
|
1.45
|
|
3%
|
Total price per Boe without hedge settlements
|
|
$
|
46.94
|
|
$
|
51.52
|
|
$
|
(4.58)
|
|
(9%)
|
Average unit costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
Field operating expenses (a)
|
|
$
|
21.04
|
|
$
|
17.82
|
|
$
|
3.22
|
|
18%
|
Lease operating expenses
|
|
$
|
19.03
|
|
$
|
15.31
|
|
$
|
3.72
|
|
24%
|
Production taxes
|
|
$
|
2.01
|
|
$
|
2.51
|
|
$
|
(0.50)
|
|
(20%)
|
Depreciation, depletion and amortization
|
|
$
|
12.76
|
|
$
|
10.93
|
|
$
|
1.83
|
|
17%
|
|
(a)
|
|
Field operating expenses include lease operating expenses (average production costs) and production taxes.
|
Production, For the year ended December 31, 2019, 74% of our production was oil, 14% was NGLs and 12% was natural gas compared to the year ended December 31, 2018, where 67% of our production was oil, 16% was NGLs and 17% was natural gas. The production mix between the periods has shifted to a higher oil production as a result of multiple asset divestitures in 2018 that were rich in natural gas. Combined production has decreased by 130 MBoe for the year ended December 31, 2019, primarily due to the closings during 2018 of the Briggs Divestiture, Louisiana Divestiture and Cola Divestiture.
Sales of natural gas, NGLs and oil. Unhedged oil sales decreased $6.3 million, or 32%, to $13.5 million for the year ended December 31, 2019, compared to approximately $19.9 million for the same period in 2018. Sales of NGLs decreased approximately $1.2 million, or 68%, to $0.5 million for the year ended December 31, 2019, compared to approximately $1.7 million for the same period in 2018. Unhedged natural gas sales decreased approximately $0.6 million, or 59%, to approximately $0.4 million for the year ended December 31, 2019, compared to approximately $1.0 million for the same period in 2018. The total decrease in sales of natural gas, NGLs and oil for the year ended December 31, 2019 was primarily the result of the same factors described under “Production” above as well as a decrease in average sales prices.
Including hedges and mark-to-market activities, our total production-related revenue decreased approximately $13.2 million for the year ended December 31, 2019, compared to the same period in 2018. This decrease was primarily the result of approximately $7.6 million of losses on oil mark-to-market activities and a decrease in oil sales of approximately $6.3 million.
The following tables provide an analysis of the impacts of changes in production volumes and average realized prices between the periods on our unhedged revenues for the year ended December 31, 2019 compared to the year ended December 31, 2018 (in thousands, except average sales prices and volumes):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
|
Average
|
|
|
|
Revenue
|
|
|
Average
|
|
Average
|
|
Sales Price
|
|
2019
|
|
Decrease
|
|
|
Sales Price
|
|
Sales Price
|
|
Difference
|
|
Volume
|
|
due to Price
|
Natural gas (MMcf)
|
|
$
|
1.84
|
|
$
|
2.39
|
|
$
|
(0.55)
|
|
231
|
|
$
|
(127)
|
Oil (MBbl)
|
|
$
|
59.40
|
|
$
|
67.14
|
|
$
|
(7.74)
|
|
228
|
|
$
|
(1,765)
|
NGLs (MBbl)
|
|
$
|
12.83
|
|
$
|
24.07
|
|
$
|
(11.24)
|
|
42
|
|
$
|
(472)
|
Total oil equivalent (MBoe)
|
|
$
|
46.94
|
|
$
|
51.52
|
|
$
|
(4.58)
|
|
309
|
|
$
|
(2,364)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Production
|
|
2018
|
|
Revenue
|
|
|
Production
|
|
Production
|
|
Volume
|
|
Average
|
|
Decrease
|
|
|
Volume
|
|
Volume
|
|
Difference
|
|
Sales Price
|
|
due to Production
|
Natural gas (MMcf)
|
|
231
|
|
434
|
|
(203)
|
|
$
|
2.39
|
|
$
|
(485)
|
Oil (MBbl)
|
|
228
|
|
296
|
|
(68)
|
|
$
|
67.14
|
|
$
|
(4,565)
|
NGLs (MBbl)
|
|
42
|
|
71
|
|
(29)
|
|
$
|
24.07
|
|
$
|
(698)
|
Total oil equivalent (MBoe)
|
|
309
|
|
439
|
|
(130)
|
|
$
|
51.52
|
|
$
|
(5,748)
|
A 10% increase or decrease in our average realized sales prices, excluding the impact of derivatives, would have increased or decreased our revenues for the year ended December 31, 2019 by approximately $1.5 million.
Hedging and mark-to-market activities. We apply mark-to-market accounting to our derivative contracts; therefore, the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in oil and natural gas revenues. For the year ended December 31, 2019, the non-cash mark-to-market losses were approximately $4.7 million, compared to gains of approximately $2.7 million for the same period in 2018. The 2019 non-cash mark-to-market loss resulted from higher future expected oil prices compared to the settlement prices on our oil fixed price basis swaps. Cash settlements received for our commodity derivatives were approximately $0.9 million for the year ended December 31, 2019, compared to settlements paid of approximately $1.4 million for the year ended December 31, 2018.
Field operating expenses. Our field operating expenses generally consist of lease operating expenses, labor, vehicles, supervision, transportation, minor maintenance, tools and supplies expenses, as well as production and ad valorem taxes.
Lease operating expenses. Lease operating expenses decreased approximately $0.8 million, or 13%, to approximately $5.9 million for the year ended December 31, 2019, compared to $6.7 million for the same period in 2018. This decrease in operating expenses was primarily due to the Briggs Divestiture, Louisiana Divestiture and Cola Divestiture that closed during 2018.
Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense includes the depreciation, depletion and amortization of acquisition costs and equipment costs. Depletion is calculated using units-of-production under the successful efforts method of accounting. Assuming other variables remain constant, as the production of natural gas, NGLs and oil increases or decreases, our depletion expense would increase or decrease as well, respectively.
Our depreciation, depletion and amortization expense for the year ended December 31, 2019 was approximately $3.9 million, compared to approximately $4.8 million for the same period in 2018. The decrease was primarily the result of the Briggs Divestiture, Louisiana Divestiture and Cola Divestiture that closed during 2018. Our non-oil and natural gas properties are depreciated using the straight-line basis.
Impairment expense. For the years ended December 31, 2019 and 2018, we did not record impairment on our oil and natural gas properties.
Consolidated Earnings Results
The following table sets forth the reconciliation of segment operating income to net income (loss) for periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Variance
|
Reconciliation of segment operating income to net income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production operating income
|
|
|
$
|
92
|
|
$
|
14,301
|
|
$
|
(14,209)
|
|
|
(99%)
|
Total midstream operating income
|
|
|
|
1,858
|
|
|
37,586
|
|
|
(35,728)
|
|
|
(95%)
|
Total segment operating income
|
|
|
|
1,950
|
|
|
51,887
|
|
|
(49,937)
|
|
|
(96%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expense
|
|
|
|
(17,610)
|
|
|
(23,653)
|
|
|
6,043
|
|
|
(26%)
|
Unit-based compensation expense
|
|
|
|
(1,351)
|
|
|
(1,938)
|
|
|
587
|
|
|
(30%)
|
Interest expense, net
|
|
|
|
(39,789)
|
|
|
(10,961)
|
|
|
(28,828)
|
|
|
NM (a)
|
Other income
|
|
|
|
5,860
|
|
|
546
|
|
|
5,314
|
|
|
NM (a)
|
Income tax expense
|
|
|
|
(202)
|
|
|
(190)
|
|
|
(12)
|
|
|
6%
|
Net income (loss)
|
|
|
$
|
(51,142)
|
|
$
|
15,691
|
|
$
|
(66,833)
|
|
|
NM (a)
|
|
(a)
|
|
Amounts Variances deemed to be Not Meaningful “NM”
|
General and administrative expenses. General and administrative expenses include indirect costs billed by Manager in connection with the Services Agreement, field office expenses, professional fees and other costs not directly associated with field operations. General and administrative expenses, inclusive of unit-based compensation expense, decreased approximately $6.0 million, or 26%, to approximately $17.6 million for the year ended December 31, 2019, compared to approximately $23.7 million for the same period in 2018. The decrease was primarily the result of reduced salaries and wages, as well as reduced asset management fees.
Unit-based compensation expense. Unit-based compensation expense decreased approximately $0.6 million, or 30%, to approximately $1.4 million for the year ended December 31, 2019, compared to approximately $1.9 million for the same period in 2018. This decrease was the result of a substantial decline in the price of our common units on the NYSE American during the two year period ended December 31, 2019.
Interest expense, net. Interest expense increased approximately $28.8 million, to approximately $39.8 million for the year ended December 31, 2019, compared to approximately $10.9 million for the same period in 2018. This increase was the result of the issuance of the Class C Preferred Units and the Warrant on August 2, 2019. The accrual of distributions on the Class C Preferred Units as well as the mark-to-market impact of the Warrant are charges to interest expense. Cash interest expense for the year ended December 31, 2019 was approximately $9.2 million compared to approximately $10.2 million for the same period in 2018. See Note 17. “Partner’s Capital” of our Notes to Consolidated Financial Statements for additional information related to Class C Preferred Units and the Warrant.
Other income (expense). Other income was approximately $5.9 million for the year ended December 31, 2019, compared to approximately $0.5 million for the same period in 2018, resulting from changes in the fair value measurement of the earnout derivative.
Income tax expense. Income tax expense was approximately $0.2 million for the years ended December 31, 2019, and 2018, respectively.
Liquidity and Capital Resources
As of December 31, 2019, we had approximately $5.1 million in cash and cash equivalents and $15.0 million available for borrowing under the Credit Agreement in effect on such date, as discussed further below. During the years ended December 31, 2019 and 2018, we paid approximately $9.2 million and $9.8 million, respectively, in cash for interest on borrowings under our Credit Agreement, of which approximately $0.2 million was related to the fee on undrawn commitments during the year ended December 31, 2019.
Our capital expenditures during the year ended December 31, 2019 were funded with cash on hand. In the future, capital and liquidity are anticipated to be provided by operating cash flows, borrowings under our Credit Agreement and proceeds from the issuance of additional common units or other limited partner interests. We expect that the combination of these capital resources will be adequate to meet our short-term working capital requirements, long-term capital expenditures program and quarterly cash distributions, if any.
We expect that our future cash requirements relating to working capital, maintenance capital expenditures and quarterly cash distributions, if any to our partners will be funded from cash flows internally generated from our operations. Our expansion capital expenditures will be funded by borrowings under our Credit Agreement or from potential capital market transactions. However, there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain our current debt level, planned levels of capital expenditures, operating expenses or any cash distributions that we may make to unitholders.
Credit Agreement
We have entered into a credit facility with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto as amended by the Ninth Amendment to Third Amended and Restated Credit Agreement (the “Credit Agreement”). The Credit Agreement provides a quarterly amortizing term loan of $155.0 million (the “Term Loan”) and a maximum revolving credit amount of $20.0 million (the “Revolving Loan”). The Term Loan and Revolving Loan both have a maturity date of September 30, 2021. Borrowings under the Credit Agreement are secured by various mortgages of both midstream and upstream properties that we own as well as various security and pledge agreements among us, certain of our subsidiaries and the administrative agent.
Borrowings under the Credit Agreement are available for limited direct investment in oil and natural gas properties, midstream properties, acquisitions, and working capital and general business purposes. The Credit Agreement has a sub-limit of up to $2.5 million which may be used for the issuance of letters of credit. Pursuant to the Credit Agreement, the initial aggregate commitment amount under the Term Loan is $155.0 million, subject to quarterly $10.0 million principal and other mandatory prepayments. The borrowing base is equal to the sum of the rolling four quarter EBITDA of our midstream operations and the amount of distributions received from the Carnero JV multiplied by 4.5 or a lower number dependent upon natural gas volumes flowing through Western Catarina Midstream. Outstanding borrowings in excess of our borrowing base must be repaid within 45 days. As of December 31, 2019, the borrowing base under the Credit Agreement was $235.5 million and we had $150.0 million of debt outstanding, consisting of $145.0 million under the Term Loan and $5.0 million under the Revolving Loan. We are required to make mandatory payments of outstanding principal on the Term Loan of $10 million per fiscal quarter. The maximum revolving credit amount is $20.0 million which left us with $15.0 million in unused borrowing capacity at December 31, 2019. There were no letters of credit outstanding under our Credit Agreement as of December 31, 2019.
At our election, interest for borrowings under the Credit Agreement are determined by reference to (i) the London interbank offered rate (“LIBOR”) plus an applicable margin between 2.50% and 3.00% per annum based on net debt to EBITDA or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.50% and 2.00% per annum based on net debt to EBITDA plus (iii) a commitment fee of 0.500% per annum based on the unutilized maximum revolving credit. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.
The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions.
In addition, we are required to maintain the following financial covenants:
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·
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current assets to current liabilities of at least 1.0 to 1.0 at all times; and
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·
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senior secured net debt to consolidated adjusted EBITDA for the last twelve months, as of the last day of any fiscal quarter, of not greater than 3.5 to 1.0.
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The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) our existing general partner ceases to be our sole general partner or (ii) certain specified persons shall cease to own more than 50% of the equity interests of our general partner or shall cease to control our general partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies.
Our partnership agreement prohibits us from paying any distributions on our common units until we have redeemed all of the Class C Preferred Units. Following such redemption, the Credit Agreement further limits our ability to pay distributions to unitholders.
At December 31, 2019, we were in compliance with the financial covenants contained in the Credit Agreement. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our Credit Agreement or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of the Credit Agreement, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted.
Sources of Debt and Equity Financing
As of December 31, 2019, we had $5.0 million of debt outstanding under the Revolving Loan, leaving us with $15.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement at December 31, 2019. Our Credit Agreement matures on September 30, 2021.
In April 2017, we issued 84,577 common units in registered offerings for gross proceeds of approximately $1.3 million pursuant to a shelf registration statement originally filed with the SEC on March 6, 2015, as supplemented by that certain prospectus supplement filed with the SEC on April 6, 2017.
Open Commodity Hedge Positions
We periodically enter into hedging arrangements to reduce the impact of oil and natural gas price volatility on our operations. By removing the price volatility from a significant portion of our projected 2020 oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flows. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices. These derivative contracts also limit our ability to have additional cash flows to fund higher severance taxes, which are usually based on market prices for oil and natural gas. Our operating cash flows are also impacted by the cost of oilfield services. In the event of inflation increasing service costs or administrative expenses, our hedging program will limit our ability to have increased operating cash flows to fund these higher costs. Increases in the market prices for oil and natural gas will also increase our need for working capital as our commodity hedging contracts cash settle prior to our receipt of cash from our sales of the related commodities to third parties.
It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. All of our derivatives are currently collateralized by the assets securing our Credit Agreement and therefore currently do not require the posting of cash collateral. This is significant since we are able to lock in sales prices on a substantial amount of our expected 2020 production without posting cash collateral based on price changes prior to the hedges being cash settled.
The following tables as of December 31, 2019, summarize, for the periods indicated, our hedges currently in place through December 31, 2020. All of these derivatives are accounted for as mark-to-market activities.
MTM Fixed Price Swaps—NYMEX (Henry Hub)
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Three Months Ended (volume in MMBtu)
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March 31,
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June 30,
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September 30,
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December 31,
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Total
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Average
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Average
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Average
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Average
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Average
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Volume
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Price
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Volume
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Price
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Volume
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Price
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Volume
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Price
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Volume
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Price
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2020
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105,104
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$
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2.85
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102,008
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$
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2.85
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99,136
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$
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2.85
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96,200
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$
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2.85
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402,448
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$
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2.85
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MTM Fixed Price Basis Swaps–West Texas Intermediate (WTI)
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Three Months Ended (volume in Bbls)
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March 31,
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June 30,
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September 30,
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December 31,
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Total
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Average
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Average
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Average
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Average
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Average
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Volume
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Price
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Volume
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Price
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Volume
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Price
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Volume
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Price
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Volume
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Price
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2020
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52,776
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$
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53.50
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50,960
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$
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53.50
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49,224
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$
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53.50
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47,624
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$
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53.50
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200,584
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$
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53.50
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Operating Cash Flows
We had net cash flows provided by operating activities for the year ended December 31, 2019, of approximately $58.0 million, compared to net cash flows provided by operating activities of approximately $66.9 million for the same period in 2018. This decrease was primarily related to the impact of lower average commodity prices between the periods resulting in lower production for the period of approximately $5.7, as well as a decrease of approximately $2.4 million.
Our operating cash flows are subject to many variables, the most significant of which is the volume of oil and natural gas transported through our midstream assets, volatility of oil and natural gas prices and our level of production of oil and natural gas. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future operating cash flows will depend on oil and natural gas transported through our midstream assets, as well as the market prices of oil and natural gas and our hedging program.
Investing Activities
We had net cash flows used in investing activities for the year ended December 31, 2019 of approximately $1.4 million, consisting of approximately $1.0 million related to midstream activities, including pipeline construction, and contributions to Carnero JV totaling approximately $0.2 million.
Our net cash flows provided by investing activities for the year ended December 31, 2018 were approximately $2.3 million, consisting of approximately $2.5 million related to midstream activities, including pipeline construction, and contributions to Carnero JV totaling approximately $2.8 million. These outflows were offset by approximately $7.7 million related to proceeds from sales of oil and natural gas properties.
Financing Activities
Net cash flows used in financing activities was approximately $54.4 million for the year ended December 31, 2019. During the year ended December 31, 2019, we distributed (i) approximately $17.7 million to Stonepeak Catarina, as the holder of all of our previously outstanding Class B Preferred Units and, starting with the distribution for the quarter ended June 30, 2019, the holder of all of our outstanding Class C Preferred Units, and (ii) approximately $5.2 million to our common unitholders. Additionally, we paid approximately $0.2 million in costs associated with the Exchange (as defined herein) and repaid $34.0 million of borrowings under the Credit Agreement.
Net cash flows used in financing activities were approximately $66.6 million for the year ended December 31, 2018. During the year ended December 31, 2018, we distributed approximately $33.3 million to Stonepeak Catarina, as the holder of all of our outstanding Class B Preferred Units, and approximately $23.2 million to our common unitholders.
Additionally, we paid approximately $0.1 million in offering costs and repaid $11.0 million of borrowings under the Credit Agreement.
Off-Balance Sheet Arrangements
As of December 31, 2019, we had no off-balance sheet arrangements with third parties, and we maintain no debt obligations that contained provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings.
Credit Markets and Counterparty Risk
We actively monitor the credit exposure and risks associated with our counterparties. Additionally, we continue to monitor global credit markets to limit our potential exposure to credit risk where possible. Our primary credit exposures result from the generation of substantially all of our midstream business segment revenues from a single customer, Sanchez Energy, the sale of oil and natural gas and our use of derivatives. On August 11, 2019, the Sanchez Energy Chapter 11 Case was filed. No assurances can be given as to the timing or outcome of this process. As of December 31, 2019, we had no past due receivables from Sanchez Energy, and through December 31, 2019, we have not suffered any significant losses with our counterparties as a result of nonperformance. However, on January 13, 2020, we received written notice of termination from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective February 12, 2020. Given our midstream focus, our primary credit exposure relates to the creditworthiness of the counterparties under our gathering and processing agreements. Sanchez Energy, whose earned revenues contribute to our midstream segment, accounted for 86% of total revenue for the year ended December 31, 2019. Any development that materially and adversely affects Sanchez Energy’s operations or financial condition could have a material adverse impact on us, including but not limited to impairment losses on fixed assets. For additional information on the risks associated with our relationships with Sanchez Energy, please read “Part I, Item 1A. Risk Factors.”
Certain key counterparty relationships are described below:
Derivative Counterparties
As of December 31, 2019, our derivatives were with ING, Comerica and Royal Bank of Canada, all of whom are lenders in our Credit Agreement. All of our derivatives are currently collateralized by the assets securing our Credit Agreement and therefore currently do not require the posting of cash collateral. As of December 31, 2019, each of these financial institutions had an investment grade credit rating.
Credit Agreement
As of December 31, 2019, the banks and their percentage commitments in our Credit Agreement were: Royal Bank of Canada (13%), BBVA USA f/k/a Compass Bank (12%), Trust Bank f/k/a SunTrust Bank (12%), Capital One, National Association (12%), Comerica Bank (12%), Citibank, N.A. (9%), Credit Suisse AG, Cayman Islands (9%), ING Capital LLC (9%), CIT Bank, N.A. (9%) and Macquarie Investments US Inc (5%). As of December 31, 2019, each of these financial institutions had an investment grade credit rating.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the calculation of depletion and impairment of oil and natural gas properties, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.
The policies disclosed included the accounting for oil and natural gas properties, oil and natural gas reserve quantities, revenue recognition and hedging activities. Please read Note 2 “Basis of Presentation and Summary of Significant Accounting Policies” to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
Oil and Natural Gas Properties
We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.
Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold and proved property acquisition costs using all proved reserves. As more fully described in Note 8 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements, proved reserves estimates are subject to future revisions when additional information becomes available.
All other properties, including gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets.
Estimated asset retirement costs are recognized when the asset is acquired or placed in service. Costs associated with oil and natural gas properties are amortized over proved reserves using the units-of-production method. Costs associated with gathering and transportation assets are depreciated using the straight-line method over the useful lives of the asset. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. Cash flow estimates for the impairment testing are based on third party reserve reports and exclude derivative instruments. Refer to Note 8 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements for additional information.
Gathering and transportation assets are reviewed for impairment when facts or circumstances indicate that their carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Refer to Note 8 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements for additional information.
Reserves of Natural Gas, NGLs and Oil
Our estimate of proved reserves is based on the quantities of natural gas, NGLs and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Management estimates the proved reserves attributable to our ownership based on various factors, including consideration of the reserve report prepared by Ryder Scott, an independent oil and natural gas consulting firm. On an annual basis, our proved reserve estimates and the reserve report prepared by Ryder
Scott are reviewed by the Audit Committee and the Board. Our financial statements for 2019 and 2018 were prepared using Ryder Scott’s estimates of our proved reserves.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.
Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the actual quantities of oil and natural gas eventually recovered.
Recent Accounting Pronouncements and Accounting Changes
See Note 2 “Basis of Presentation and Summary of Significant Accounting Policies” to our consolidated financial statements included in this report for information on new accounting pronouncements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required by this Item.
Item 8. Financial Statements and Supplementary Data
The information required by this Item is included in this report as set forth in the “Index to Consolidated Financial Statements” beginning on page F‑1 of this Form 10-K and is incorporated by reference herein.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, with the Partnership have been detected. These inherent limitations include error by personnel in executing controls due to faulty judgment or simple mistakes, which could occur in situations such as when personnel performing controls are new to a job function or when inadequate resources are applied to a process. Additionally, controls can be circumvented by the individual acts of some persons or by collusion of two or more people.
The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no absolute assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions or personnel, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. The principal executive officer and principal financial officer of our general partner have concluded that our current disclosure controls and procedures were effective as of December 31, 2019 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
During the three months ended December 31, 2019, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Reports of Management
Financial Statements
The management of our general partner is responsible for the information and representations in our financial statements. We prepare the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management’s best estimates and judgments of known conditions.
The Audit Committee, which consists of three independent directors, meets periodically with management, our internal auditor and KPMG LLP to review the activities of each in discharging their responsibilities. Our internal auditor and KPMG LLP have free access to the Audit Committee.
Management’s Report on Internal Control Over Financial Reporting
Our management, under the direction of the principal executive officer and principal financial officer of our general partner, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Exchange Act.
Our system of internal control over financial reporting is designed to provide reasonable assurance to our management and the Board regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.
The management of our general partner conducted an evaluation of the effectiveness of our internal control over financial reporting using the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). As noted in the COSO framework, an internal control system, no matter how well conceived and operated, can provide only reasonable-not absolute-assurance to management and the Board regarding achievement of an entity’s financial reporting objectives. Based upon the evaluation under this framework, management concluded that our internal control over financial reporting was effective as of December 31, 2019.
Report of Independent Registered Public Accounting Firm
Please see Report of Independent Public Accounting Firm under “Part II, Item 8. Financial Statements and Supplementary Data” of this Form 10-K.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The following table shows information for members of the Board and the executive officers of our general partner as of March 13, 2020. All of the directors of our general partner are elected by Manager, as the sole member of our general partner, except for two persons who are appointed by Stonepeak Catarina pursuant to the Representation and Standstill Agreement. Members of the Board hold office until their successors have been elected or qualified or until the earlier of their death, incapacity, resignation or removal. Executive officers hold office at the discretion of, and may be removed by, the Board.
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Name
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Age
|
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Position with Sanchez Midstream Partners LP
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Alan S. Bigman
|
|
52
|
|
Independent Director
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Kirsten A. Hink
|
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53
|
|
Chief Accounting Officer
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Jack Howell
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33
|
|
Director
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Richard S. Langdon
|
|
69
|
|
Independent Director
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G.M. Byrd Larberg
|
|
67
|
|
Independent Director
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Antonio R. Sanchez, III
|
|
46
|
|
Director; Chairman of the Board
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Eduardo A. Sanchez
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|
40
|
|
Director
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Patricio D. Sanchez
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|
39
|
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Director; President & Chief Operating Officer
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Luke R. Taylor
|
|
42
|
|
Director
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Charles C. Ward
|
|
59
|
|
Chief Financial Officer & Secretary
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Gerald F. Willinger
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52
|
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Director; Chief Executive Officer
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Alan S. Bigman was elected as a member of the Board in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in July 2014. Mr. Bigman is an independent member of the Conflicts Committee of our general partner and is the Chair of the Audit Committee of our general partner. Mr. Bigman currently serves as an independent non-executive director and chairman of the audit committee of a $1.5 billion dollar privately held chemicals company. His extensive board experience also includes Basell Polyolefins, an international chemical producer and predecessor of LyondellBasell, where he served as a non-executive director before his appointment as Chief Financial Officer, and Svyazinvest, then Russia’s largest telecom company, as well as several others. Mr. Bigman’s executive experience includes fourteen years in positions with Access Industries, a privately-held, U.S.-based industrial group, and in senior positions with its portfolio companies. From June 1996 to March 1998, Mr. Bigman was Senior Vice President of Access Industries, overseeing strategic investments. From March 1998 until September 2003, Mr. Bigman served as Vice President and Director of Corporate Finance of Tyumen Oil Company (TNK), a major Russian oil and gas producer and refiner, where he raised over $5 billion to finance the growth of the company from its privatization in 1997 through a sale of a 50% stake to British Petroleum (BP) in 2003, creating TNK-BP, a $20 billion joint venture. From 2003 to 2004, he served as Vice President and Director of Corporate Finance for SUAL, a large Russian aluminum smelter, where he reorganized the finance function and executed strategic merger transactions. From September 2004 until December 2005, Mr. Bigman rejoined Access Industries as Senior Vice President. In January 2006, Mr. Bigman was appointed Chief Financial Officer of Basell Polyolefins, an international chemicals company based in The Netherlands, where he served through 2007 and co-led the acquisition of Lyondell to create one of the largest global chemical companies. In January 2008 Mr. Bigman was appointed Chief Financial Officer of LyondellBasell Industries, the successor company to Basell Polyolefins and Lyondell. LyondellBasell's US operations filed for bankruptcy in January 2009. Mr. Bigman continued to serve as Chief Financial Officer until August 2009, and worked for the company in a project role through March 2010. From 2011 through 2012, he served on a project basis as Director, Capital Markets and M&A of KCAD Deutag, an oilfield services company based in Aberdeen, UK, where he was responsible for reorganizing and staffing the company’s finance, corporate development and tax functions.
Kirsten A. Hink was elected Chief Accounting Officer of our general partner in May 2015. Mrs. Hink has served as Senior Vice President and Chief Accounting Officer of Sanchez Energy since January 2015, and she previously served as Sanchez Energy’s Vice President and Principal Accounting Officer from March 2012. Sanchez Energy filed the Sanchez Energy Chapter 11 Case in August 2019. Mrs. Hink has served as Senior Vice President – Chief Accounting Officer of SOG since March 2016. Prior to joining Sanchez Energy, Mrs. Hink served as Controller of Vanguard Natural Resources, LLC from January 2011 to February 2012. From January 2010 to December 2010, she served as Assistant Controller of Mariner Energy, Inc. She served as the Chief Accounting Officer for Edge Petroleum Corporation, or Edge, from July 2008 through December 2009 and the Vice President and Controller for Edge from October 2003 through July 2008. Prior to that time, she served as Controller of Edge from December 31, 2000 to October 2003 and Assistant Controller of Edge from June 2000 to December 2000. Edge filed for bankruptcy in October 2009. Mrs. Hink is a Certified Public Accountant in the State of Texas.
Jack Howell was elected as a member of the Board in October 2015. Mr. Howell is a Senior Managing Director at Stonepeak and a member of Stonepeak’s Executive Committee. Mr. Howell has been with Stonepeak since 2015. Prior to joining Stonepeak, Mr. Howell covered the oil and gas sector for Davidson Kempner, a hedge fund that focuses on distressed investments, from 2014 to 2015. Prior to Davidson Kempner, Mr. Howell worked for Denham Capital, an energy-focused private equity firm from 2011 to 2014. Mr. Howell started his career as an Analyst in Credit Suisse’s oil and gas investment banking group. Mr. Howell holds a Bachelor of Arts degree in Plan II Honors and Business Economics, Phi Beta Kappa, from the University of Texas at Austin.
Richard S. Langdon was elected as a member of the Board in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in December 2006. Mr. Langdon is an independent member of the Audit Committee and the Conflicts Committee. Mr. Langdon is currently the Executive Vice President and Chief Financial Officer of Altamont Energy LLC, a privately held exploration and production company. Mr. Langdon previously served as the President and Chief Executive Officer of Badlands Energy, Inc., a privately held exploration and production company (“Badlands Energy”), and its publicly traded predecessor entity, Gasco Energy, Inc. (“Gasco”), from May 2013 to October 2018. Mr. Langdon also served as a director of Badlands Energy and its predecessor, Gasco since 2003. Badlands Energy filed for bankruptcy in August 2017. In addition to his Badlands Energy titles, Mr. Langdon also served as Debtor-in-Possession for Badlands Energy, Inc from August 2017 to October 2018. Mr. Langdon also currently serves on the board of directors, as chairman of the audit committee and as a member of the compensation committee of Gulfslope Energy, Inc., which capacities he has served in since March 2014. Mr. Langdon was the President and Chief Executive Officer of KMD Operating Company LLC (“KMD Operating”), a privately held production company, from November 2011 until December 2015 and Matris Exploration Company L.P., a privately held production company, from July 2004 until the merger of Matris Exploration into KMD Operating in November 2011, which merger was effective January 2011. Mr. Langdon also served as President and Chief Executive Officer of Sigma Energy Ventures, LLC, a privately held production company, from November 2007 until November 2013. From 1997 until 2002, Mr. Langdon served as Executive Vice President and Chief Financial Officer of EEX Corporation, a publicly traded exploration and production company that merged with Newfield Exploration Company in 2002. Prior to that, he held various positions with the Pennzoil Companies from 1991 to 1996, including Executive Vice President—International Marketing—Pennzoil Products Company; Senior Vice President—Business Development—Pennzoil Company; and Senior Vice President—Commercial & Control—Pennzoil Exploration & Production Company.
G. M. Byrd Larberg was elected as a member of the Board in March 2015. He was previously a director of Sanchez Production Partners LLC, having been first elected in July 2014. Mr. Larberg is an independent member of the Audit Committee and is the Chair of the Conflicts Committee. Mr. Larberg served as a member of the board of directors of Horizon Energy, a private Exploration Company with both domestic and international focus, from 2017 to 2019. From 2010 to 2012, Mr. Larberg served as a member of the board of directors of Risco Resources, a small independent exploration company headquartered in Jakarta, Indonesia, which was sold in 2012. Mr. Larberg served as a member of the board of directors of 3GIG, an exploration-focused software firm headquartered in Houston, Texas, from 2008 to 2013 and now serves as an advisor to the board. He is active on the board of directors of the Houston Metropolitan YMCA and was previously chairman of the board. He was a member of the board of directors of Meridian Resources, a Houston-based exploration company, from 2007 until it was acquired by Alta Mesa in 2010. Mr. Larberg began his career at Shell Exploration and Production Company as a geologist in 1976. Over the next 21 years, he held various leadership positions within various Shell entities, and served as Vice President of Exploration and Production, Africa and Latin America for Pecten International, an affiliate of Shell Oil Company, from 1993 to 1996. Mr. Larberg left Shell and joined Burlington
Resources in 1998. From 1998 to 2006, Mr. Larberg held several key positions at Burlington Resources, beginning as Vice President of Exploration for Burlington Resources International. In 2000, Mr. Larberg was elected Executive Vice President and Chief Operating Officer of Burlington Resources International, a position he held until 2003, when he moved to the corporate office as Vice President of Geosciences. In this capacity, he was responsible for technical excellence for the geology and geophysical (“G&G”) programs across the company, G&G technology business development, and management of the company-wide exploration portfolio. Mr. Larberg retired from Burlington Resources in April 2006 following the company’s purchase by ConocoPhillips. Mr. Larberg was a director of Duma Hydrocarb Energy Corporation, a publicly traded production company, for a brief period in 2014. He occasionally consults in the areas of technical and portfolio management for exploration companies, and has provided such consulting services to a number of companies including Pemex, Maersk, ONGC, Ecopetrol, Repsol, HOCOL and the Kuwait National Petroleum Company.
Antonio R. Sanchez, III was elected as a member of the Board in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in August 2013. Mr. Sanchez, III is Chairman of the Board. He currently serves as the President & Chief Executive Officer of Sanchez Energy and has been a member of Sanchez Energy’s board of directors since its formation in August 2011. Sanchez Energy filed the Sanchez Energy Chapter 11 Case in August 2019. He has been directly involved in the oil and gas industry for over 13 years. Mr. Sanchez, III is also the Co-President of SOG, which he joined in October 2001. He was the President of SEP Management I, LLC and was a Managing Director of Sanchez Energy Partners I, LP until their dissolution in December 2016. In his capacities as a director and officer of these companies, Mr. Sanchez, III has managed all aspects of their daily operations, including exploration, production, finance, capital markets activities, engineering and land management. From 1997 to 1999, Mr. Sanchez, III was an investment banker specializing in mergers and acquisitions with J.P. Morgan Securities Inc. From 1999 to 2001, Mr. Sanchez, III worked in a variety of positions, including sales and marketing, product development and investor relations, at Zix Corporation, a publicly traded encryption technology company (NASDAQ: ZIXI). Mr. Sanchez, III was also a member of the board of directors of Zix Corporation from May 2003 to June 2014.
Eduardo A. Sanchez was elected as a member of the Board in June 2015. Mr. Sanchez served as president of Sanchez Energy from October 2015 to November 2017, President and Chief Executive Officer of Sanchez Resources, LLC from February 2010 until November 2017, co-president of SOG from July 2014 to November 2017, and chief executive officer of Sanchez Oil & Gas Mexico Holdings, LLC from August 2015 to December 2017. Sanchez Energy filed the Sanchez Energy Chapter 11 Case in August 2019. Prior to his work at Sanchez Resources, LLC, Mr. Sanchez worked at Commonwealth Associates, Inc. focusing on private equity and debt placements in small and midsize market capitalization businesses including those in the energy sector.
Patricio D. Sanchez was elected President & Chief Operating Officer of our general partner in March 2017, Chief Operating Officer of our general partner in May 2015 and as a member of the Board in June 2015. Mr. Sanchez has served as co-president of SOG since June 2014 and prior to that from April 2010 to June 2014 as an Executive Vice President. Mr. Sanchez has served as an Executive Vice President of Sanchez Energy since November 2016. Sanchez Energy filed the Sanchez Energy Chapter 11 Case in August 2019. Mr. Sanchez has also been the managing member of Santerra Holdings, LLC, an oil and gas production company, since February 2012. Mr. Sanchez has managed many aspects of these companies’ daily operations, including exploration, production, finance, capital markets activities, engineering and land management.
Luke R. Taylor was elected as a member of the Board in October 2015. Mr. Taylor has served as a Senior Managing Director with Stonepeak since August 2011 and serves as a member of Stonepeak’s Executive Committee. Mr. Taylor has been investing across the infrastructure space for over 15 years and sits on the boards of Lineage Logistics, Golar Power and Ironclad Energy Partners, and is a former director of Paradigm Energy Partners, Tidewater Holdings, Carlsbad Desalination Project, Casper Crude to Rail and Northstar Renewable Power. Prior to joining Stonepeak, Mr. Taylor was a Senior Vice President with Macquarie Capital based in New York. Mr. Taylor has a Bachelor of Commerce and a Master of Business (Distinction) from the University of Otago (New Zealand).
Charles C. Ward was elected Chief Financial Officer & Secretary of our general partner in March 2015. He previously served as Chief Financial Officer and Treasurer of Sanchez Production Partners LLC from March 2008 until its conversion to a limited partnership in March 2015 and Secretary from July 2014 until March 2015. Mr. Ward also served as a Vice President of Constellation Energy Commodities Group, Inc. from November 2005 until December 2008. Prior to that time, he was a Vice President of Enron Creditors Recovery Corp. from March 2002 to November 2005.
Gerald F. Willinger was elected as a member of the Board in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in August 2013. Mr. Willinger was elected Interim Chief Executive Officer of our general partner in April 2015 and Chief Executive Officer in December 2015. Mr. Willinger has served as a Managing Director of Sanchez Capital Advisors, LLC since February 2010 and as Executive Vice President of SOG since 2014. Mr. Willinger was also a co-founder, officer and director of Sanchez Resources from February 2010 to November 2017 when Sanchez Resources was acquired by Sanchez Energy Corporation. From 1998 to 2000, Mr. Willinger was an investment banker with Goldman, Sachs & Co. Mr. Willinger served in various private equity investment management roles at MidOcean Partners, LLC and its predecessor entity, DB Capital Partners, LLC, from 2000 to 2003 and at the Cypress Group, LLC from 2003 to 2006. Prior to joining Sanchez Capital Advisors, LLC, Mr. Willinger was a Senior Analyst for Silver Point Capital, LLC, a credit-opportunity fund, from 2006 to 2009.
Messrs. Howell and Taylor were elected as members of the Board in October 2015 pursuant a Board Representation and Standstill Agreement, by and among us, our general partner and Stonepeak Catarina, which was subsequently amended and restated by that certain Amended and Restated Board Representation and Standstill Agreement, dated as of August 2, 2019, by and among us, our general partner and Stonepeak Catarina (as amended and restated, the “Representation and Standstill Agreement”). Pursuant to the Representation and Standstill Agreement, we and our general partner agreed to permit Stonepeak Catarina to designate two persons to serve on the Board. The right to designate one Board member will immediately terminate on such date as Stonepeak Catarina no longer owns at least 25% of the Partnership’s outstanding Class C Preferred Units issued to it; and the right to designate the second Board member will immediately terminate on such date as Stonepeak Catarina does not hold any issued and outstanding Class C Preferred Units. Stonepeak Catarina also has the right to appoint the three independent members to the Board if all of the Class C Preferred Units have not been redeemed by December 31, 2021, with such right continuing until all Class C Preferred Units have been redeemed.
Messrs. Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez are brothers.
Qualifications of the Board of Directors
The sole member of our general partner elects all of the members of the Board, except for two members designated by Stonepeak Catarina pursuant to the Representation and Standstill Agreement. The following sets forth the specific experience, qualifications, attributes and skills that led the sole member of our general partner to conclude that the persons appointed by it should serve as directors:
Mr. Bigman brings considerable financial, managerial, transaction and corporate governance experience to the Board. During his career, he has held management positions of increasing responsibility in major energy corporations throughout the world where he has successfully lead financings, financial restructurings, mergers and acquisitions involving companies focused on various aspects of the hydrocarbon value chain. With respect to energy finance, as Vice President and Director of Corporate Finance for TNK, a leading Russian oil and gas producer, he raised capital to finance the growth of the company from its privatization in 1997 through a sale of a 50% stake to British Petroleum (BP) in 2003, creating TNK-BP, a $20 billion joint venture. In the area of corporate governance, Mr. Bigman served on the board of directors of Basell Polyolefins, where he was a member of the audit and compensation committees, which is beneficial for our board operations. He has also served on several international boards, including the board of Svyazinvest, Russia’s largest telecommunications holding company, and JKX Oil and Gas, a UK public company focused on international oil and gas assets.
Mr. Langdon brings considerable financial and managerial experience in the energy industry to the Board as well as his entrepreneurial abilities, all of which are valuable to the Board. He has served as the Chief Financial Officer of EEX Corporation, a publicly traded production company that merged with Newfield Exploration. He has also held significant commercial positions with the Pennzoil Companies, including roles in business development and marketing. He was also the founder and owner of two privately held oil and gas companies. Mr. Langdon has extensive experience in finance and accounting that adds significant value to the board’s oversight role of our financial reporting. He has prior public company board and audit committee experience, which is beneficial for our board operations, and served as the chairman of the audit committee of Gasco until he was named Gasco’s President and Chief Executive Officer.
Mr. Larberg brings significant technical, operational and financial management experience in the oil and natural gas industry to the Board. His background provides a unique perspective on the dynamics of the oil and natural gas
production industry. He has considerable governance experience, having previously served on the boards of several other companies. Taken together, this wealth of experience is invaluable to our board.
Mr. Sanchez, III brings substantial oil and gas/energy industry experience in both public and private entities to the Board. In his current capacity as President & Chief Executive Officer of Sanchez Energy and as a member of the board of directors of Sanchez Energy, he brings the perspective of leading a publicly-traded upstream company. In his current capacity as Co-President of SOG, he brings particular expertise in operating multiple oil and natural gas entities through a shared service model.
Mr. Eduardo Sanchez brings substantial oil and gas/energy industry experience in both public and private entities to the Board. Through his past experience as the President of Sanchez Energy and co-president of SOG, he brings the perspective of leading a publicly-traded upstream company and particular expertise in operating multiple oil and natural gas entities through a shared service model.
Mr. Patricio Sanchez brings substantial oil and gas/energy industry experience in both public and private entities to the Board. As an Executive Vice President at Sanchez Energy, he brings the perspective of leading a publicly-traded upstream company. In his current capacity as Co-President of SOG, he brings particular expertise in operating multiple oil and gas entities through a shared service model.
Mr. Willinger brings substantial experience in risk management, finance and negotiated transactions in the energy industry to the Board. He has a valuable perspective on master limited partnerships, which provides the Board with unique insights into master limited partnership management and growth opportunities. In addition, he brings an expansive network of both private and public capital providers, which is useful for the Board when evaluating possible capital sources.
The following sets forth the specific experience, qualifications, attributes and skills that led the holders of our Class C Preferred Units to conclude that the persons appointed by them should serve as directors:
Mr. Howell brings extensive oil and gas investing experience, along with experience in oil and gas transaction financings and mergers and acquisitions to the Board.
Mr. Taylor brings significant investment experience in energy and infrastructure companies, along with experience in finance and mergers and acquisitions to the Board.
Committees of the Board of Directors
The Board has two standing committees: the Audit Committee and the Conflicts Committee. We do not have a compensation committee, but rather the Board approves executive officer salary changes and bonuses and equity grants to directors, executive officers, employees and service providers.
Audit Committee
As described in its charter, the Audit Committee is directly responsible for the appointment, compensation, retention and oversight of the work of the independent public accountants to audit our financial statements, including assessing the independent auditor’s qualifications and independence, and establishes the scope of, and oversees, the annual audit. The Audit Committee also approves any other services provided by public accounting firms. The Board has delegated to the Audit Committee the review and approval of our decision to enter into derivative transactions and our exemption from the swap clearing and swap execution requirements of the Dodd-Frank Act. The Audit Committee provides assistance to the Board in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The Audit Committee oversees our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the Board established. In doing so, it is the responsibility of the Audit Committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and our management.
Messrs. Bigman (Chair), Langdon and Larberg are members of the Audit Committee. The Board has determined that Mr. Bigman is an “audit committee financial expert” as that term is defined in the applicable rules of the SEC and that he is “independent” as defined in applicable NYSE American listing standards.
Conflicts Committee
The Board has appointed a standing Conflicts Committee composed of the independent directors, Messrs. Larberg, (Chair), Bigman and Langdon, to review specific matters that the Board believes may involve conflicts of interest. The Conflicts Committee will review and evaluate the proposal, negotiate as the Conflicts Committee deems appropriate the terms of the proposal and determine if the resolution of a conflict of interest is fair and reasonable to us. If the Conflicts Committee approves a conflict of interest proposal, the proposal is then recommended to the entire Board. The members of the Conflicts Committee may not be security holders, officers or employees of our general partner, directors, officers, or employees of affiliates of the general partner or holders of any ownership interest in us other than common units or other publicly traded units and must meet the independence standards established by the NYSE American, the Exchange Act and other federal securities laws. If any resolution or course of action by our general partner or its affiliates with respect to a conflict of interest is approved by the Conflicts Committee, then such resolution or course of action shall be permitted and deemed approved by all of our partners, and shall not constitute a breach of our partnership agreement, or of any duty stated or implied by law or equity.
Other
We maintain on our website, http://www.sanchezmidstream.com, a copy of the Audit Committee charter as well as copies of the Corporate Governance Guidelines and Code of Business Conduct and Ethics that are applicable to us and our general partner. Copies of these documents are also available in print and may be obtained without charge, upon written request, by emailing our investor relations group at ir@sanchezmidstream.com. Our Code of Business Conduct and Ethics applies to our general partner’s principal executive officer, principal financial officer and principal accounting officer, among others. We intend to post any changes to or waivers of our Code of Business Conduct and Ethics for the executive officers of our general partner on our website.
Certifications
The NYSE American requires the Chief Executive Officer of each listed company to certify annually that he is not aware of any violation by a listed company of the NYSE American’s corporate governance listing standards, qualifying the certification to the extent necessary. In accordance with the rules of the NYSE American, we last provided such a certification on March 18, 2019. The certifications of the Chief Executive Officer and Chief Financial Officer of our general partners required by Sections 302 and 906 of the Sarbanes-Oxley Act have been included as exhibits to this Form 10-K.
Item 11. Executive Compensation
Our general partner has the sole responsibility for conducting our business and for managing our operations, and its Board makes decisions on our behalf. The executive officers of our general partner are employed by SOG and manage the day-to-day affairs of our business.
Summary Compensation Table
The following table sets forth the compensation of our named executive officers (which are the chief executive officer and the two next most highly compensated officers of our general partner) for 2019 and 2018:
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Cash
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Unit
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All Other
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Name and Principal Position
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Year
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Salary (a)
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Bonus (b)
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Awards (c)
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Compensation (d)
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Total
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Gerald F. Willinger
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2019
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$
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600,000
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$
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750,000
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$
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1,502,953
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$
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60,229
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$
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2,913,182
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Chief Executive Officer (e)
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2018
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$
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600,000
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$
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750,000
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$
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1,799,980
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$
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128,994
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$
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3,278,974
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Patricio D. Sanchez
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2019
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$
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400,000
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$
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—
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$
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—
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$
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19,273
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$
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419,273
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President & Chief Operating Officer (e)
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2018
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$
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400,000
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$
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—
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$
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1,299,989
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$
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52,043
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$
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1,752,032
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Charles C. Ward
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2019
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$
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375,000
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$
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350,000
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$
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635,864
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$
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45,367
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$
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1,406,231
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Chief Financial Officer and Secretary (e)
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2018
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$
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275,000
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$
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350,000
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$
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849,995
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$
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40,476
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$
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1,515,471
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(a)
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On January 30, 2019, the Board increased Mr. Ward’s base salary from $275,000 to $375,000 effective as of January 1, 2019.
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(b)
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On August 2, 2019, the Board approved the Partnership’s entry into Executive Agreements (defined below) with each of Messrs. Willing and Ward. The Executive Agreements contain annual cash bonuses ranges for each of Messrs. Willinger and Ward and also stipulate that, for the 2019 annual cash bonus, 50% of such bonuses were required to be paid no later than September 30, 2019 with the remainder to be paid no later than March 31, 2020. Pursuant to this requirement in the Executive Agreements, Messrs. Willinger and Ward were paid cash bonuses of $375,000 and $175,000 respectively, on September 30, 2019, as part of their 2019 annual cash bonus. Pursuant to the Executive Agreements (as defined below), we will pay Messrs. Ward and Willinger the remaining 50% of their 2019 annual cash bonuses on or before March 31, 2020.
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(c)
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The amounts reported in this column reflect the aggregate grant date fair value of awards granted, if any, under our Plan for fiscal years 2019 and 2018, computed in accordance with FASB ASC Topic 718, excluding estimated forfeitures. See Note 15 “Unit-Based Compensation,” to the Consolidated Financial Statements included under “Part II, Item 8. Financial Statements and Supplementary Data” for additional detail regarding these figures. On March 4, 2019, the Board awarded Messrs. Willinger and Ward long-term incentive awards, which were paid in the form of restricted units under the Plan that vest in equal installments over three years.
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(d)
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The amount in this column reflects the amount of matching contributions made under our 401k plan; parking cost paid for our executive officers; the cost of life insurance, accidental death and dismemberment insurance, and health insurance for our executive officers; and for those executive officers who also serve as directors, this column includes cash fees they received for service as a director.
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(e)
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Our named executive officers are eligible to participate in benefit plans such as medical, dental, vision, life and disability insurance, 401k and flexible spending accounts on the same terms as all employees or service providers.
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Executive Agreements
On August 2, 2019, our general partner entered into Executive Services Agreements with each of Messrs. Willinger and Ward (each, an “Executive Agreement” and, collectively, the “Executive Agreements”). The Executive Agreements were approved by the Board on August 2, 2019. Each respective Executive Agreement provides (i) that the applicable executive will continue to serve in his current executive officer position with our general partner and provide services to us and our general partner during the applicable term, (ii) for an annual base salary (Mr. Willinger: $600,000 and Mr. Ward: $375,000), (iii) for an annual cash bonus equal to a percentage of the annual base salary (Mr. Willinger: 100%-150% and Mr. Ward: 75%-125%) based on a qualitative assessment of financial and individual performance achievements, and (iv) for eligibility to receive awards under our Plan or any successor thereto and to participate in any long-term incentive programs available generally to the executive officers of our general partner, as determined in the sole discretion of the Board. Under each Executive Agreement, in the event of the applicable executive’s termination as an officer of the general partner due to (a) such executive’s death or “disability,” (b) the general partner terminating such executive without “cause,” or (c) such executive terminating for “good reason” (as such terms are defined in the Executive Agreements), such executive (or such executive’s designated beneficiaries, as applicable) will be entitled to receive payment of: (i) any accrued but unpaid then-current annual base salary through the date of termination, (ii) any unpaid annual bonus for the year prior to the year of termination and (iii) a pro-rated annual bonus for the year of termination. In addition, such executive will also be entitled to receive the following severance payments or benefits in the event of: (1) the general partner terminating such executive without “cause” (2) such executive terminating for “good reason” or (3)(A) the general partner terminating such executive without “cause,” (B) such executive’s death or “disability,” or (C) such executive terminating for any reason, in the case of (A)-(C), during a period beginning 60 days prior to and ending two years following a Change in Control (as defined in the Executive Agreements) such executive will be entitled to receive (w) a lump-sum cash payment equal to two times such executive’s then-current annual base salary plus two times the largest annual bonus paid (or due to be paid) to such executive for the year in which the termination occurs or any year in the three calendar year period immediately preceding the date of termination, (x) payment of the COBRA premiums for such
executive and such executive’s eligible dependents during the COBRA continuation period, (y) to the extent not yet paid to such executive, a lump-sum cash payment equal to all outstanding amounts owed to such executive for services performed for or on behalf of us and our general partner, the amount of such executive’s annual bonus for the last full year during which such executive performed services for us and our general partner, and the amount of such executive’s annual bonus for the current year, based on such executive’s annual bonus for such last full year (pro-rated to the date of termination), and (z) immediate vesting in full, as of the date of such Change in Control, of any units awarded to such executive under our Plan.
Outstanding Equity Awards at Fiscal Year-End 2019
The following table sets forth the outstanding equity awards and their market value using the closing price of our common units on NYSE American at December 31, 2019 for the named executive officers:
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Number of
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Fair Market
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Units Not
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Value of Units
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Name
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Vested
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Not Vested⁽ᵃ⁾
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Gerald F. Willinger
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576,185
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(b)
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$
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172,856
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Patricio D. Sanchez
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—
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$
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—
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Charles C. Ward
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248,665
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(b)
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$
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74,600
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(a)
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Amounts are based on the closing price of our common units of $0.30 as reported on the NYSE American on December 31, 2019.
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(b)
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Reflects restricted units granted under the Plan on April 6, 2018, which units either vest on the first anniversary of the grant date or vest pro-rata over a three-year period and on their first anniversary, respectively, as well as units granted under the Plan on March 4, 2019, which units vest pro-rata over a three year period. See footnote (c) to the Summary Compensation Table for additional information on the vesting schedule for these units. Except in connection with a change in control (as defined in the Plan) or in the discretion of the board of directors of our general partner, any unvested restricted units will be forfeited upon such time as the holder is no longer an officer, employee, consultant or director of us, our general partner, any of their affiliates or any other person performing bona fide services for us.
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Compensation of Directors
For the year ended December 31, 2019, compensation for the independent directors of the Board consisted of:
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a cash retainer of $10,000, payable quarterly on the last day of each fiscal quarter;
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·
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an equity grant of $100,000 of fully vested common units on March 31 of each year;
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·
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a $1,500 fee for each meeting of the Board and $1,000 for each substantive meeting of the Audit Committee and $3,500 for each substantive meeting of the Conflicts Committee attended by a member thereof;
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·
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a cash retainer of $3,500 for the Chair of the Audit Committee and $2,500 for the Chair of the Conflicts Committee, each payable quarterly on the last day of each fiscal quarter; and
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·
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eligibility for independent directors to participate in health benefits generally available to all employees and reimbursement for up to $500,000 of life and accidental death and dismemberment insurance.
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Directors designated by Stonepeak, officers of our general partner and any director with ownership interests in SP Holdings, LLC, were not eligible for the 2019 director compensation program outlined above. However, on January 30, 2019, the Board approved a long-term incentive award for Mr. A. Sanchez, which was paid in the form of 210,970 restricted units under the Plan that vest in equal installments over three years.
The following table sets forth a summary of the 2019 compensation for the directors except for Messrs. Willinger and P. Sanchez whose director compensation is included above under “—Summary Compensation Table”:
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|
|
|
|
|
|
|
|
|
Director Compensation
|
|
|
Fees Earned or Paid
|
|
Unit
|
|
All Other
|
|
|
|
Name
|
|
in Cash
|
|
Awards (a)
|
|
Compensation (b)
|
|
Total
|
Alan S. Bigman
|
|
$
|
69,500
|
|
$
|
99,990
|
|
$
|
21,155
|
|
$
|
190,645
|
Jack Howell (c)
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
Richard S. Langdon
|
|
$
|
55,500
|
|
$
|
99,990
|
|
$
|
1,020
|
|
$
|
156,510
|
G. M. Byrd Larberg
|
|
$
|
62,000
|
|
$
|
99,990
|
|
$
|
15,681
|
|
$
|
177,671
|
Antonio R. Sanchez, III (d)
|
|
$
|
—
|
|
$
|
578,058
|
|
$
|
—
|
|
$
|
578,058
|
Eduardo A. Sanchez (d)
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
Luke R. Taylor (c)
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
(a)
|
|
The amounts shown in this column for Messrs. Bigman, Langdon and Larberg represent the aggregate grant date fair value of the units granted under the Plan to Messrs. Bigman, Langdon and Larberg, computed in accordance with FASB ASC Topic 718, based on the $2.18 closing price per common unit on April 1, 2019. The amount shown in this column for Mr. A. Sanchez represents the aggregate grant date fair value of the units granted under the Plan to Mr. A. Sanchez, computed in accordance with FASB ASC Topic 718, based on the $2.74 closing price per common unit on March 4, 2019.
|
|
(b)
|
|
All other compensation includes amounts for health, vision, dental, basic life and/or accidental death and dismemberment insurance premium fees paid by us for the director.
|
|
(c)
|
|
As appointees of the holders of the Class C Preferred Units, Messrs. Howell and Taylor were not entitled to any compensation under our 2019 Board compensation program.
|
|
(d)
|
|
As individuals with ownership interests in SP Holdings, Mr. A. Sanchez and Mr. E. Sanchez and Mr. P. Sanchez where not entitled to any compensation under our 2019 board compensation program, however, as noted above, Mr. A. Sanchez was awarded restricted units by the Board outside of the 2019 Board compensation program.
|
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table sets forth the beneficial ownership of our units, as of March 13, 2020, held by:
|
·
|
|
each unitholder known by us to beneficially own more than 5% of our outstanding units;
|
|
·
|
|
each of the directors of the Board;
|
|
·
|
|
each of our general partner’s named executive officers (as such term is defined by the SEC); and
|
|
·
|
|
the directors and executive officers of our general partner as a group.
|
The list of persons named in the table below is derived from our review of Form 3, Form 4, Form 5, Schedule 13D and Schedule 13G filings made with the SEC as of March 13, 2020. The amounts and percentage of common units and Class C Preferred Units beneficially owned are reported on the basis of the SEC rules governing the determination of beneficial ownership of securities. Under the SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, and/or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities, and a person may be deemed a beneficial owner of securities as to which he has no economic interest.
Percentage of total units beneficially owned is based on 19,975,193 common units and 34,297,357 Class C Preferred Units outstanding as of March 13, 2020, the number of common units beneficially owned and the number of Class C Preferred Units beneficially owned is based upon ownership as of March 13, 2020, unless otherwise specified. Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
|
Common Units Beneficially
|
|
Class C Preferred Units
|
|
Total Units
|
|
|
Owned
|
|
Beneficially Owned
|
|
Beneficially
|
Name and address of Beneficial Owner(1)
|
|
Number
|
|
Percentage
|
|
Number
|
|
Percentage
|
|
Owned
|
Stonepeak Catarina Holdings, LLC(2)
|
|
2,312,100
|
|
10.6
|
%
|
|
34,297,357
|
|
100
|
%
|
|
65.2
|
%
|
SN UR Holdings, LLC(3)
|
|
2,272,727
|
|
11.4
|
%
|
|
—
|
|
—
|
|
|
4.2
|
%
|
Invesco. Ltd(4)
|
|
1,758,705
|
|
8.8
|
%
|
|
—
|
|
—
|
|
|
3.2
|
%
|
Alan S. Bigman(5)
|
|
77,254
|
|
*
|
|
|
—
|
|
—
|
|
|
*
|
|
Kirsten A. Hink
|
|
23,933
|
|
*
|
|
|
—
|
|
—
|
|
|
*
|
|
Jack Howell
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
Richard S. Langdon
|
|
81,827
|
|
*
|
|
|
—
|
|
—
|
|
|
*
|
|
G. M. Byrd Larberg
|
|
76,096
|
|
*
|
|
|
—
|
|
—
|
|
|
*
|
|
Antonio R. Sanchez, III(6)
|
|
1,337,508
|
|
6.7
|
%
|
|
—
|
|
—
|
|
|
2.5
|
%
|
Eduardo A. Sanchez
|
|
1,141,846
|
|
5.7
|
%
|
|
—
|
|
—
|
|
|
2.1
|
%
|
Patricio D. Sanchez
|
|
1,291,574
|
|
6.4
|
%
|
|
—
|
|
—
|
|
|
2.4
|
%
|
Luke R. Taylor
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
Charles C. Ward
|
|
381,048
|
|
1.9
|
%
|
|
—
|
|
—
|
|
|
*
|
|
Gerald F. Willinger
|
|
1,104,614
|
|
5.5
|
%
|
|
—
|
|
—
|
|
|
2.0
|
%
|
All directors and executive officers as a group (11 persons)
|
|
5,515,700
|
|
27.6
|
%
|
|
—
|
|
—
|
|
|
10.2
|
%
|
*Less than 1%
|
(1)
|
|
Unless otherwise set forth below, the address of all beneficial owners is c/o Sanchez Midstream Partners LP, 1000 Main Street, Suite 3000, Houston, Texas 77002.
|
|
(2)
|
|
Ownership data as reported (i) on Schedule 13D/A filed on August 6, 2019 by Stonepeak Catarina Holdings LLC, Stonepeak Catarina Upper Holdings LLC, Stonepeak Infrastructure Fund (Orion AIV) LP, Stonepeak Associates LLC, Stonepeak GP Holdings LP, Stonepeak GP Investors LLC, Stonepeak GP Investors Manager LLC, Michael Dorrell and Trent Vichie (the “Stonepeak Beneficial Owners”), and (ii) publicly disclosed information regarding distributions of Class C Preferred PIK Units issued to Stonepeak Catarina Holdings LLC following the effective date of the Exchange, consisting of 939,327 Class C Preferred PIK Units issued on August 30, 2019, 1,007,820 Class C Preferred PIK Units issued on November 29, 2019 and 1,039,314 Class C Preferred PIK Units issued on February 28, 2020. The number of common units disclosed in the Schedule 13D/A includes 1,918,809 common units that the Stonepeak Beneficial Owners currently have the right to acquire within the next 60 days upon exercise of a Warrant held by Stonepeak Catarina Holdings LLC, such common units are not included for any other person on this table in accordance with Rule 13d-3(d)(1)(i) under the Exchange Act. The principal business address of each reporting person in the Schedule 13D/A is 55 Hudson Yards, 550 W. 34th St., 48th Floor, New York, NY 10001. The Schedule 13D/A filing lists each filing person as having shared voting and dispositive power over the common units and the Class C Preferred Units.
|
|
(3)
|
|
Ownership data as reported on Schedule 13D filed on November 28, 2016 by SN UR Holdings, LLC and Sanchez Energy Corporation. The principal business address of each filing reporting person is 1000 Main Street, Suite 3000, Houston, Texas 77002. The filing lists each filing person as having shared voting and dispositive power over the common units.
|
|
(4)
|
|
Ownership data as reported on a Schedule 13G filing dated February 13, 2020 by Invesco Ltd. The principle business address of the reporting person is 1555 Peachtree Street NE, Suite 1800, Atlanta, GA 30309. The filing lists the reporting person as having sole voting and dispositive power over the common units.
|
|
(5)
|
|
Of these common units, 1,000 are held by Mr. Bigman’s minor children.
|
|
(6)
|
|
Of these common units, 35,320 are owned directly by SOG. SOG is managed by Mr. Sanchez and other members of the Sanchez family. Mr. Sanchez shares voting and dispositive power over the securities controlled by SOG. Mr. Sanchez disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.
|
Equity Compensation Plan Information
The following table reflects our equity compensation plan information for our only equity compensation plan, the Sanchez Midstream Partners LP Long-Term Inventive Plan (the “Plan”), as of December 31, 2019:
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
Securities
|
|
|
|
|
Number of securities
|
|
|
to be issued upon
|
|
Weighted-average
|
|
remaining available
|
|
|
exercise of
|
|
exercise price of
|
|
for future
|
|
|
outstanding options,
|
|
outstanding options,
|
|
issuance under equity
|
|
|
warrants, and rights
|
|
warrants, and rights
|
|
compensation plans
|
Plan Category
|
|
|
|
|
|
|
|
Equity compensation plans approved by security holders
|
|
—
|
|
$
|
—
|
|
840,811
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
—
|
Total
|
|
—
|
|
$
|
—
|
|
840,811
|
Item 13. Certain Relationships and Related Transactions, and Director Independence
Manager
We are controlled by our general partner, Sanchez Midstream Partners GP LLC. The sole member of our general partner is Manager, which has no officers. The sole manager and member of Manager is SP Capital Holdings, LLC, which has no officers. The co-managers of SP Capital Holdings, LLC are Antonio R. Sanchez, III, a member of the Board and the Chairman of the Board; Eduardo A. Sanchez, a member of the Board; Patricio D. Sanchez, a member of the Board and the President and Chief Operation Officer of our general partner; and their father, Antonio R. Sanchez, Jr. SP Capital Holdings, LLC is owned by Antonio R. Sanchez, III (26%), Eduardo A. Sanchez (26%), and Patricio D. Sanchez (26%), along with their sister, Ana Lee Sanchez Jacobs (18%), and their father, Antonio R. Sanchez, Jr (4%).
In connection with providing the services under the Services Agreement, Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Prior to August 2, 2019 each of these fees, not including the reimbursement of costs, was paid in cash unless Manager elected for such fee to be paid in our equity. However, on August 2, 2019, we and Manager entered into a letter agreement providing that until such time as we redeem all of our issued and outstanding Class C Preferred Units, Manager will elect to receive its fees, not including reimbursement of costs, in common units rather than cash. In addition, on November 8, 2019, we and Manager entered into an additional letter agreement providing that during the period beginning with the fiscal quarter ended September 30, 2019 and continuing until the end of the fiscal quarter after the fiscal quarter in which we redeem all of our issued and outstanding Class C Preferred Units (the “Tolling Period”), Manager agrees to delay receipt of its fees, not including reimbursement of costs. During the Tolling Period, we are required to keep an accurate ledger of the dollar amount of the fee applicable to each quarter within the Tolling Period and the daily closing price of our common units on the NYSE. Following the end of the Tolling Period we will provide a notice to Manager including such ledgers and pay the accrued fees within thirty days of delivery of such notice. The Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless we or Manager provide notice of termination to the other with at least 180 days’ notice. For the fees earned during the three months ended March 31, 2019 and June 30, 2019, Manager elected to receive 1,789,010 common units equal to approximately $3.9 million, in lieu of cash. For the fees earned during the three months ended September 30, 2019 and December 31, 2019, pursuant to the November 8, 2019 letter agreement, Manager did not receive any fees, other than reimbursement of its costs. However, pursuant to the requirements under the November 8, 2019 letter agreement, we have determined that the fees earned during the three months ended September 30, 2019 and December 31, 2019, are approximately $1.9, and $1.5 million, respectively. During the years ended December 31, 2019 and 2018, we incurred costs of approximately $7.3 million and $8.6 million, respectively, to Manager under the Services Agreement.
SOG
SOG provides services to us through a contractual relationship with SP Holdings. Antonio R. Sanchez, III and Patricio D. Sanchez are Co-Presidents of SOG; Antonio R. Sanchez, Jr. is the Chief Executive Officer and sole director of SOG; Ana Lee Sanchez Jacobs is an Executive Vice President of SOG; and Gerald F. Willinger is an Executive Vice President of SOG. The controlling owners of SOG are Antonio R. Sanchez, Jr. and Santig, Ltd. The general partner of Santig, Ltd. is Sanchez Management Corporation, which is owned 100% by Antonio R. Sanchez, Jr. Antonio R. Sanchez, Jr. is Chairman and President of Sanchez Management Corporation and Antonio R. Sanchez, III is Executive Vice President of Sanchez Management Corporation. For the years ended December 31, 2019 and 2018, SOG received $0.2 million and $0.3 million, respectively, as a result of its Services Agreement with SP Holdings.
Sanchez Energy
Since January 1, 2015, we have completed three midstream acquisitions and two working interest acquisitions from Sanchez Energy. Antonio R. Sanchez, Jr., the father of Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez, is a director and Executive Chairman of the board of directors of Sanchez Energy, Antonio R. Sanchez, III, is a director and President and Chief Executive Officer of Sanchez Energy, Eduardo A. Sanchez is the former President of Sanchez Energy and Patricio D. Sanchez is an Executive Vice President of Sanchez Energy. The employees of SOG, including Kirsten A. Hink, our Chief Accounting Officer, provide common services to both us and Sanchez Energy. The beneficial ownership of Sanchez Energy’s common stock as of March 13, 2020 by Antonio R. Sanchez, Jr., Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez was 6.1%, 3.0%, 1.1% and 1.2%, respectively. As of March 13, 2020, Sanchez Energy indirectly, through one of its wholly owned subsidiaries, beneficially owned approximately 11.4% of the outstanding common units of SNMP.
We entered into the Gathering Agreement with Sanchez Energy in October 2015. For the years ended December 31, 2019 and 2018, Sanchez Energy paid us approximately $59.4 million and $57.9 million, respectively, pursuant to the terms of the Gathering Agreement. On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by Sanchez Energy based on water that is delivered through the gathering system through March 31, 2018. Subsequent to the conclusion of the incremental infrastructure fee amendment, the parties have agreed to continue the incremental infrastructure fee on a month-to-month basis. On January 1, 2019 and April 1, 2019, the Partnership increased the Western Catarina Midstream tariff rate for throughput volumes that are outside of the dedicated acreage under the Gathering Agreement.
As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. For the years ended December 31, 2019 and 2018, we made earnout payments to Sanchez Energy of $32.0 thousand and $64.0 thousand, respectively.
In September 2017, we entered into the Seco Pipeline Transportation Agreement. For the years ended December 31, 2019 and 2018, Sanchez Energy paid us approximately $6.8 million and $7.2 million, respectively, pursuant to the terms of such agreement. On January 13, 2020, we received written notice from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective February 12, 2020.
In May 2018, the Carnero JV, which is operated by Targa, received a dedication from Sanchez Energy and its working interest partners of over 315,000 acres located in the Western Eagle Ford on Sanchez Energy’s Comanche Asset pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Sanchez Energy, which was approved by all of the unaffiliated Comanche working interest partners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the joint ventures limited by the capacity of the Raptor Gas Processing Facility.
Stonepeak
Class B Preferred Unit Issuance
In accordance with our partnership agreement, in December 2016, we issued an additional 9,851,996 Class B Preferred Units to Stonepeak. Stonepeak disagreed with our calculation of the additional Class B Preferred Units due under our partnership agreement and in January 2017, we and Stonepeak entered into a settlement agreement to settle the disputed calculation. Pursuant to the settlement agreement, and in accordance with Section 5.4 of our partnership agreement then in effect, we issued 1,704,446 Class B Preferred Units to Stonepeak in a privately negotiated transaction as consideration for the Settlement Agreement, with the “Class B Preferred Unit Price” under our partnership agreement being established at $11.29 per Class B Preferred Unit.
In July 2018, the Partnership elected to pay the second-quarter 2018 distribution on the Class B Preferred Units in part cash and part in Class B Preferred PIK Units. Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B Preferred Unit and an aggregate distribution of 310,009 Class B Preferred PIK Units, which was paid on August 31, 2018 to Stonepeak.
Class C Preferred Unit Issuance
On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”) in a privately negotiated transaction (the “Exchange”). In connection with the Exchange, the Partnership entered into (i) the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement) to set forth the terms of the Class C Preferred Units, (ii) the Amended and Restated Registration Rights Agreement with Stonepeak relating to the registered resale of common units issuable upon the exercise of the Warrant, and (iii) the Amended and Restated Board Representation and Standstill Agreement with Stonepeak. In addition, on August 2, 2019, the Partnership’s general partner entered into Amendment No. 3 to its Limited Liability Company Agreement to provide certain changes necessary in connection with the Exchange.
On August 8, 2019, the Board declared that after establishing a cash reserve for the payment of certain amounts outstanding under the Credit Agreement, the Partnership did not have any available cash and, as a result, there would be no cash distribution on the Partnership’s common units. As required by the Amended Partnership Agreement, the Board declared a second quarter distribution on the Class C Preferred Units payable 100% in Class C Preferred PIK Units. Accordingly, the Partnership declared an aggregate distribution of 939,327 Class C Preferred PIK Units, paid on August 30, 2019 to holders of record on August 20, 2019.
On October 30, 2019, the Board declared that after establishing a cash reserve for the payment of certain amounts outstanding under the Credit Agreement, the Partnership did not have any available cash and, as a result, there would be no cash distribution on the Partnership’s common units. As required by the Amended Partnership Agreement, the Board declared a third quarter distribution on the Class C Preferred Units payable 100% in Class C Preferred PIK Units. Accordingly, the Partnership declared an aggregate distribution of 1,007,820 Class C Preferred PIK Units, paid on November 29, 2019 to holders of record on November 20, 2019.
Warrant
On August 2, 2019, in connection with the Exchange, Stonepeak Catarina received the Warrant. The Warrant may be exercised at any time and from time to time during the period beginning on August 2, 2019 and ending on the later of the seventh anniversary of such date and the date thirty days after the date on which all of the Class C Preferred Units have been redeemed for a number of Junior Securities (as such term is defined in the Warrant) equal to 10% of each applicable class of Junior Securities then outstanding as of the exercise date. No exercise price will be payable in connection with the exercise of the Warrant.
Item 14. Principal Accounting Fees and Services
We engaged our principal accountant, KPMG LLP (“KPMG”), to audit our financial statements and perform other professional services for the fiscal years ended December 31, 2019 and 2018.
Audit Fees. The aggregate fees billed for the financial statement audit or services provided in connection with statutory or regulatory filings for the years ended December 31, 2019 and 2018 were $978,885 and $1,192,912, respectively.
Audit-Related Fees. There were no audit-related fees billed by KPMG for the years ended December 31, 2019 and 2018.
Tax Fees. There were no tax fees billed by KPMG for the years ended December 31, 2019 and 2018.
All Other Fees. There were no other fees billed by KPMG for the years ended December 31, 2019 and 2018.
Audit Committee Pre-Approval Policies and Practices
The Audit Committee must pre-approve any audit and permissible non-audit services performed by our independent registered public accounting firm. In addition, the Audit Committee has oversight responsibility to ensure that the independent registered public accounting firm is not engaged to perform certain enumerated non-audit services, including, but not limited to, bookkeeping, financial information system design and implementation, appraisal or valuation services, internal audit outsourcing services and legal services. The Audit Committee has adopted an audit and non-audit services pre-approval policy, which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent registered public accounting firm must be approved. Pursuant to the policy, all services must be reviewed and approved and the chairman of the Audit Committee has been delegated the authority to specifically pre-approve services, which pre-approval is subsequently reviewed with the committee. All of the services described as Audit Fees, Audit-Related Fees, Tax Fees and All Other Fees were approved by the Audit Committee.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as a part of this Form 10-K:
1. Financial Statements:
See Item 8. Financial Statements and Supplementary Data.
2. Financial Statement Schedules:
None.
3. Exhibits Required by Item 601 of Regulation S-K.
The exhibits required by Item 601 of Regulation S-K are listed in subparagraph (b) below.
(b) The following exhibits are filed or furnished with this Form 10-K or incorporated by reference:
On June 2, 2017 we changed our name to Sanchez Midstream Partners LP from Sanchez Production Partners LP.
HIDDEN_ROW
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
|
2.1
|
|
Contribution Agreement, dated as of August 9, 2013, by and between Constellation Energy Partners LLC and Sanchez Energy Partners I, LP (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K field by Constellation Energy Partners LLC on August 9, 2013, File No. 001-33147).
|
|
|
|
2.2
|
|
Purchase and Sale Agreement, dated as of March 31, 2015, between SEP Holdings III, LLC, Sanchez Production Partners LP and SEP Holdings IV, LLC (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on April 1, 2015, File No. 001-33147).
|
|
|
|
2.3
|
|
Purchase and Sale Agreement, dated as of September 25, 2015, by and among Sanchez Energy Corporation, SN Catarina, LLC and Sanchez Production Partners LP (incorporated herein by reference to Exhibit 2.1 the Current Report on Form 8-K filed by Sanchez Production Partners LP on September 29, 2015, File No. 001-33147).
|
|
|
|
2.4
|
|
Purchase and Sale Agreement by and among Sanchez Energy Corporation, SN Midstream, LLC and Sanchez Production Partners LP, dated July 5, 2016 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on August 12, 2016, File No. 001-33147).
|
|
|
|
2.5
|
|
Purchase and Sale Agreement, dated October 6, 2016, by and among Sanchez Energy Corporation, SN Midstream, LLC and Sanchez Production Partners LP (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 7, 2016, File No. 001-33147).
|
|
|
|
2.6
|
|
Purchase and Sale Agreement, dated October 6, 2016, by and among SN Cotulla Assets, LLC, SN Palmetto, LLC, SEP Holdings IV, LLC and Sanchez Production Partners LP (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 7, 2016, File No. 001-33147).
|
|
|
|
2.7
|
|
Purchase and Sale Agreement, dated October 6, 2016, by and among Sanchez Energy Corporation, SN Terminal, LLC and Sanchez Production Partners LP (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 7, 2016, File No. 001-33147).
|
2.8
|
|
Membership Interest Purchase and Sale Agreement, dated May 10, 2017, between Sanchez Midstream Partners LP (f/k/a Sanchez Production Partners LP) and Exponent Energy, LLC (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
|
|
|
|
2.9
|
|
Purchase and Sale Agreement, dated June 30, 2017, between SEP Holdings IV, LLC and Sendero Petroleum, LLC (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
|
|
|
|
2.10
|
|
Amendment No. 1 to Purchase and Sale Agreement, dated July 31, 2017, between SEP Holdings IV, LLC and Sendero Petroleum, LLC (incorporated by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
|
|
|
|
2.11
|
|
Purchase and Sale Agreement between Sanchez Midstream Partners LP and Dallas Petroleum Group, LLC dated October 12, 2017 (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on November 14, 2017, File No. 001-33147).
|
|
|
|
2.12
|
|
Agreement to Purchase Oil and Gas Interests between SEP Holdings IV, LLC and EP Energy E&P Company, L.P., dated April 30, 2018 (incorporated herein by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on May 10, 2018, File No. 001-33147).
|
3.1
|
|
Certificate of Conversion of Sanchez Production Partners LLC (incorporated herein by reference to Exhibit 4.1 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
|
|
|
|
3.2
|
|
Certificate of Limited Partnership of Sanchez Production Partners LP (incorporated herein by reference to Exhibit 4.2 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
|
|
|
|
3.3
|
|
Certificate of Amendment to Certificate of Limited Partnership (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on June 2, 2017, File No. 001-33147).
|
3.4
|
|
Third Amended and Restated Agreement of Limited Partnership of Sanchez Production Partners LP (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 5, 2019, File No. 001-33147).
|
|
|
|
3.5
|
|
Certificate of Formation of Sanchez Production Partners GP LLC (incorporated by reference to Exhibit 4.4 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
|
3.6
|
|
Limited Liability Company Agreement of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 4.5 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
|
|
|
|
3.7
|
|
Amendment No. 1 to Limited Liability Company Agreement of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q/A filed by Sanchez Production Partners LP on September 3, 2015, File No. 001-33147).
|
|
|
|
|
|
|
3.8
|
|
Amendment No. 2 to Limited Liability Company Agreement of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).
|
|
|
|
3.9
|
|
Amendment No. 3 to Limited Liability Company Agreement of Sanchez Production Partners GP LLC, dated August 2, 2019 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on August 5, 2019, File No. 001-33147).
|
|
|
|
4.1
|
|
Registration Rights Agreement, dated November 22, 2016, between Sanchez Production Partners LP and SN UR Holdings, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on November 22, 2016, File No. 001-33147).
|
|
|
|
4.2
|
|
Amended and Restated Registration Rights Agreement, dated August 2, 2019, by and among Sanchez Midstream Partners LP and Stonepeak Catarina Holdings LLC (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 5, 2019, File No. 001-33147).
|
4.3*
|
|
Description of Registrant Securities.
|
10.1
|
|
Purchase Agreement, dated November 16, 2016, between Sanchez Production Partners LP and SN UR Holdings, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on November 22, 2016, File No. 001-33147).
|
|
|
|
10.2
|
|
Third Amended and Restated Credit Agreement, dated as of March 31, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on April 1, 2015, File No. 001-33147).
|
|
|
|
10.3
|
|
Amendment and Waiver of Third Amended and Restated Credit Agreement, dated as of August 12, 2015, between Sanchez Production Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on August 14, 2015, File No. 001-33147).
|
|
|
|
10.4
|
|
Joinder, Assignment and Second Amendment to Third Amended and Restated Credit Agreement, dated as of October 14, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).
|
|
|
|
10.5
|
|
Third Amendment to Third Amended and Restated Credit Agreement, dated as of November 12, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on November 13, 2015, File No. 001-33147).
|
|
|
|
10.6
|
|
Fourth Amendment to Third Amended and Restated Credit Agreement among Sanchez Production Partners LP, the guarantors party thereto, each of the lenders party thereto, and Royal Bank of Canada, as administrative agent and collateral agent, dated July 5, 2016 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on August 12, 2016, File No. 001-33147).
|
|
|
|
10.7
|
|
Fifth Amendment to the Third Amended and Restated Credit Agreement dated as of April 17, 2017, between Sanchez Production Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on May 15, 2017, File No. 001-33147).
|
10.8
|
|
Sixth Amendment to the Third Amended and Restated Credit Agreement dated as of November 7, 2017, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on November 14, 2017, File No. 001-33147).
|
10.9
|
|
Seventh Amendment to the Third Amended and Restated Credit Agreement dated as of February 5, 2018, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated by reference to Exhibit 10.11 to the Annual Report on Form 10-K filed by Sanchez Midstream Partners LP on March 12, 2018, File No. 001-33147).
|
10.10
|
|
Eighth Amendment to the Third Amended and Restated Credit Agreement dated as of May 7, 2018, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on May 10, 2018, File No. 001-33147).
|
10.11
|
|
Ninth Amendment to the Third Amended and Restated Credit Agreement dated as of May 7, 2018, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada as Administrative Agent and as Collateral Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on November 25, 2019, File No. 001-33147).
|
10.12*
|
|
Summary Compensation of Executive Officers of Sanchez Midstream Partners GP LLC.
|
|
|
|
10.13*
|
|
Summary Compensation of Directors of Sanchez Midstream Partners GP LLC.
|
|
|
|
10.14
|
|
Amended and Restated Shared Services Agreement, dated as of March 6, 2015, between SP Holdings, LLC and Sanchez Production Partners LP (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on May 15, 2015, File No. 001-33147).
|
|
|
|
10.15
|
|
Contract Operating Agreement, dated May 8, 2014, between Constellation Energy Partners LLC and Sanchez Oil & Gas Corporation (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Constellation Energy Partners LLC on May 8, 2014, File No. 001-33147).
|
|
|
|
10.16
|
|
Geophysical Seismic Data Use License Agreement, dated May 8, 2014, between Constellation Energy Partners, LLC, certain subsidiaries thereof, and Sanchez Oil & Gas Corporation (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed by Constellation Energy Partners LLC on May 8, 2014, File No. 001-33147).
|
|
|
|
10.17
|
|
Amendment One to License Agreement, dated as of March 6, 2015, by and among Sanchez Oil and Gas Corporation, Sanchez Production Partners LP and SEP Holdings IV, LLC (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on May 15, 2015, File No. 001-33147).
|
|
|
|
10.18
|
|
Firm Gathering and Processing Agreement, dated as of October 14, 2015, by and between Catarina Midstream, LLC and SN Catarina, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).
|
|
|
|
10.19
|
|
Amendment No. 1 to Firm Gathering and Processing Agreement by and between SN Catarina, LLC and Catarina Midstream, LLC, dated June 30, 2017 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
|
10.20+
|
|
Sanchez Production Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 4.6 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
|
|
|
|
10.21+
|
|
Form of Award Agreement Relating to Restricted Units (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on December 3, 2015, File No. 001-33147).
|
|
|
|
10.22+
|
|
Form of Award Agreement Relating to Restricted Units (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on March 28, 2017, File No. 001-33147).
|
10.23
|
|
Settlement Agreement and Release, effective January 25, 2017, by and between Stonepeak Catarina Holdings LLC and Sanchez Production Partners LP (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on January 27, 2017, File No. 001-33147).
|
10.24+
|
|
Form of Award Agreement Relating to Restricted Units incorporated by reference to Exhibit 10.24 to the Annual Report on Form 10-K filed by Sanchez Midstream Partners LP on March 7, 2019, File No. 001-33147.
|
10.25
|
|
Amended and Restated Board Representation and Standstill Agreement, dated August 2, 2019, by and among Sanchez Midstream Partners LP, Sanchez Midstream Partners GP LLC and Stonepeak Catarina Holdings LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 5, 2019, File No. 001-33147).
|
10.26+
|
|
Form of Executive Services Agreement (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners on August 8, 2019, File No. 001-33147).
|
10.27
|
|
Warrant Exercisable for Junior Securities, dated August 2, 2019, by and between Sanchez Midstream Partners LP and Stonepeak Catarina Holdings LLC (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 5, 2019, File No. 001-33147).
|
21.1*
|
|
List of subsidiaries of Sanchez Midstream Partners LP.
|
|
|
|
*Filed herewith
+Management contract or compensatory plan or arrangement.
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
Sanchez Midstream Partners LP
|
|
|
|
|
By:
|
Sanchez Midstream Partners GP LLC,
|
|
|
its general partner
|
|
|
|
Date: March 13, 2020
|
By
|
/S/ Gerald F. Willinger
|
|
Name
|
Gerald F. Willinger
|
|
Title
|
Chief Executive Officer
|
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below, constitutes and appoints Gerald F. Willinger and Charles C. Ward, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite or necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
This report has been signed below by the following persons on behalf of the general partner of the registrant and in the capacities and on the dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
|
/s/ Antonio R. Sanchez, III
|
|
Director; Chairman of the Board
|
|
March 13, 2020
|
|
Antonio R. Sanchez, III
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Gerald F. Willinger
|
|
Director; Chief Executive Officer
|
|
March 13, 2020
|
|
Gerald F. Willinger
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
|
/S/ Charles C. Ward
|
|
Chief Financial Officer & Secretary
|
|
March 13, 2020
|
|
Charles C. Ward
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
|
|
/S/ Patricio D. Sanchez
|
|
Director; President & Chief Operating Officer
|
|
March 13, 2020
|
|
Patricio D. Sanchez
|
|
(Principal Operating Officer)
|
|
|
|
|
|
|
|
|
|
/S/ Kirsten A. Hink
|
|
Chief Accounting Officer
|
|
March 13, 2020
|
|
Kirsten A. Hink
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
|
|
/S/ Alan S. Bigman
|
|
Director
|
|
March 13, 2020
|
|
Alan S. Bigman
|
|
|
|
|
|
|
|
|
|
|
|
/S/ Jack Howell
|
|
Director
|
|
March 13, 2020
|
|
Jack Howell
|
|
|
|
|
|
|
|
|
|
|
|
/S/ Richard S. Langdon
|
|
Director
|
|
March 13, 2020
|
|
Richard S. Langdon
|
|
|
|
|
|
|
|
|
|
|
|
/S/ G. M. Byrd Larberg
|
|
Director
|
|
March 13, 2020
|
|
G. M. Byrd Larberg
|
|
|
|
|
|
|
|
|
|
|
|
/S/ Eduardo A. Sanchez
|
|
Director
|
|
March 13, 2020
|
|
Eduardo A. Sanchez
|
|
|
|
|
|
|
|
|
|
|
|
/S/ Luke R. Tayler
|
|
Director
|
|
March 13, 2020
|
|
Luke R. Taylor
|
|
|
|
|
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of Sanchez Midstream Partners LP and the Board of Directors of Sanchez Midstream Partners GP LLC
Sanchez Midstream Partners LP:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Sanchez Midstream Partners LP and subsidiaries (the Partnership) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the years in the two‑year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the two‑year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/KPMG LLP
We have served as the Partnership’s auditor since 2013.
Houston, Texas
March 13, 2020
SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES
Consolidated Statements of Operations
(In thousands, except unit data)
|
|
|
|
|
|
|
Years Ended
|
|
December 31,
|
|
2019
|
|
2018
|
Revenues
|
|
|
|
|
|
Natural gas sales
|
$
|
683
|
|
$
|
953
|
Oil sales
|
|
9,512
|
|
|
21,272
|
Natural gas liquid sales
|
|
539
|
|
|
1,709
|
Gathering and transportation sales
|
|
6,825
|
|
|
6,651
|
Gathering and transportation lease revenues
|
|
59,090
|
|
|
53,025
|
Total revenues
|
|
76,649
|
|
|
83,610
|
Expenses
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
Lease operating expenses
|
|
7,378
|
|
|
7,864
|
Transportation operating expenses
|
|
11,553
|
|
|
12,316
|
Production taxes
|
|
621
|
|
|
1,104
|
General and administrative expenses
|
|
17,610
|
|
|
23,653
|
Unit-based compensation expense
|
|
1,351
|
|
|
1,938
|
Gain on sale of assets
|
|
—
|
|
|
(3,186)
|
Depreciation, depletion and amortization
|
|
25,333
|
|
|
25,987
|
Asset impairments
|
|
32,119
|
|
|
—
|
Accretion expense
|
|
526
|
|
|
497
|
Total operating expenses
|
|
96,491
|
|
|
70,173
|
Other (income) expense
|
|
|
|
|
|
Interest expense, net
|
|
39,789
|
|
|
10,961
|
Earnings from equity investments
|
|
(2,831)
|
|
|
(12,859)
|
Other income
|
|
(5,860)
|
|
|
(546)
|
Total other (income) expenses
|
|
31,098
|
|
|
(2,444)
|
Total expenses
|
|
127,589
|
|
|
67,729
|
Income (loss) before income taxes
|
|
(50,940)
|
|
|
15,881
|
Income tax expense
|
|
202
|
|
|
190
|
Net income (loss)
|
|
(51,142)
|
|
|
15,691
|
Preferred unit paid-in-kind distributions
|
|
(14,409)
|
|
|
(3,500)
|
Preferred unit distributions
|
|
(8,838)
|
|
|
(33,425)
|
Preferred unit amortization
|
|
(1,708)
|
|
|
(2,358)
|
Deemed contribution
|
|
103,773
|
|
|
—
|
Net income (loss) attributable to common unitholders - Basic
|
|
27,676
|
|
|
(23,592)
|
Mark-to-market on Warrant
|
|
(3,244)
|
|
|
—
|
Net income (loss) attributable to common unitholders - Diluted
|
$
|
24,432
|
|
$
|
(23,592)
|
Net income (loss) per unit
|
|
|
|
|
|
Common units - Basic
|
$
|
1.46
|
|
$
|
(1.55)
|
Common units - Diluted
|
$
|
1.23
|
|
$
|
(1.55)
|
Weighted average units outstanding
|
|
|
|
|
|
Common units - Basic
|
|
18,939,145
|
|
|
15,264,284
|
Common units - Diluted
|
|
19,810,679
|
|
|
15,264,284
|
See accompanying notes to consolidated financial statements.
SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES
Consolidated Balance Sheets
(In thousands, except unit data)
|
|
|
|
|
|
|
December 31,
|
|
2019
|
|
2018
|
ASSETS
|
|
|
|
|
Current assets
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
5,099
|
|
$
|
2,934
|
Accounts receivable
|
|
133
|
|
|
277
|
Accounts receivable - related entities
|
|
6,719
|
|
|
6,700
|
Prepaid expenses
|
|
1,193
|
|
|
931
|
Fair value of commodity derivative instruments
|
|
226
|
|
|
3,044
|
Total current assets
|
|
13,370
|
|
|
13,886
|
Oil and natural gas properties and related equipment
|
|
|
|
|
|
Oil and natural gas properties, equipment and facilities (successful efforts method)
|
|
112,476
|
|
|
112,173
|
Gathering and transportation assets
|
|
186,941
|
|
|
186,406
|
Less: accumulated depreciation, depletion, amortization and impairment
|
|
(144,189)
|
|
|
(100,245)
|
Oil and natural gas properties and equipment, net
|
|
155,228
|
|
|
198,334
|
Other assets
|
|
|
|
|
|
Intangible assets, net
|
|
145,246
|
|
|
158,706
|
Fair value of commodity derivative instruments
|
|
—
|
|
|
876
|
Equity investments
|
|
100,311
|
|
|
114,465
|
Other non-current assets
|
|
285
|
|
|
418
|
Total assets
|
$
|
414,440
|
|
$
|
486,685
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS' CAPITAL
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
$
|
5,347
|
|
$
|
4,678
|
Accounts payable and accrued liabilities - related entities
|
|
631
|
|
|
5,641
|
Royalties payable
|
|
359
|
|
|
359
|
Short-term debt, net of debt issuance costs
|
|
39,374
|
|
|
—
|
Fair value of commodity derivative instruments
|
|
985
|
|
|
6
|
Other liabilities
|
|
—
|
|
|
125
|
Total current liabilities
|
|
46,696
|
|
|
10,809
|
Other liabilities
|
|
|
|
|
|
Long term accrued liabilities - related entities
|
|
4,892
|
|
|
—
|
Asset retirement obligation
|
|
6,898
|
|
|
6,200
|
Long-term debt, net of debt issuance costs
|
|
109,437
|
|
|
178,582
|
Class C Preferred Units
|
|
281,688
|
|
|
—
|
Other liabilities
|
|
629
|
|
|
5,857
|
Total other liabilities
|
|
403,544
|
|
|
190,639
|
Total liabilities
|
|
450,240
|
|
|
201,448
|
Commitments and contingencies (See Note 13)
|
|
|
|
|
|
Mezzanine equity
|
|
|
|
|
|
Class B Preferred Units, zero and 31,310,896 units issued and outstanding as of December 31, 2019 and 2018, respectively
|
|
—
|
|
|
349,857
|
Partners' deficit
|
|
|
|
|
|
Common units, 20,087,462 and 16,486,239 units issued and outstanding as of December 31, 2019 and 2018, respectively
|
|
(35,800)
|
|
|
(64,620)
|
Total partners' deficit
|
|
(35,800)
|
|
|
(64,620)
|
Total liabilities and partners' deficit
|
$
|
414,440
|
|
$
|
486,685
|
See accompanying notes to consolidated financial statements.
SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES
Consolidated Statements of Cash Flows
(In thousands)
|
|
|
|
|
|
|
Years Ended
|
|
December 31,
|
|
2019
|
|
2018
|
Cash flows from operating activities:
|
|
|
|
|
|
Net income (loss)
|
$
|
(51,142)
|
|
$
|
15,691
|
Adjustments to reconcile net income (loss) to cash provided by operating activities:
|
|
|
|
|
|
Depreciation and depletion
|
|
11,873
|
|
|
12,527
|
Amortization of debt issuance costs
|
|
1,266
|
|
|
783
|
Accretion of Class C discount
|
|
13,129
|
|
|
—
|
Class C distribution accrual
|
|
19,309
|
|
|
—
|
Asset impairments
|
|
32,119
|
|
|
—
|
Accretion expense
|
|
526
|
|
|
497
|
Distributions from equity investments
|
|
17,227
|
|
|
24,946
|
Equity earnings in affiliate
|
|
(2,831)
|
|
|
(12,859)
|
Gain on sale of assets
|
|
—
|
|
|
(3,186)
|
Mark-to-market on Warrant
|
|
(3,244)
|
|
|
—
|
Net loss (gain) on commodity derivative contracts
|
|
3,772
|
|
|
(1,316)
|
Net cash settlements received (paid) on commodity derivative contracts
|
|
1,101
|
|
|
(1,326)
|
Unit-based compensation
|
|
1,351
|
|
|
1,938
|
Gain on earnout derivative
|
|
(5,856)
|
|
|
(546)
|
Amortization of intangible assets
|
|
13,460
|
|
|
13,460
|
Changes in Operating Assets and Liabilities:
|
|
|
|
|
|
Accounts receivable
|
|
(6)
|
|
|
(377)
|
Accounts receivable - related entities
|
|
(23)
|
|
|
6,389
|
Prepaid expenses
|
|
(262)
|
|
|
1,739
|
Other assets
|
|
83
|
|
|
82
|
Accounts payable and accrued liabilities
|
|
6,378
|
|
|
13,719
|
Accounts payable and accrued liabilities- related entities
|
|
(122)
|
|
|
(5,333)
|
Royalties payable
|
|
—
|
|
|
(12)
|
Other long-term liabilities
|
|
(123)
|
|
|
126
|
Net cash provided by operating activities
|
|
57,985
|
|
|
66,942
|
Cash flows from investing activities:
|
|
|
|
|
|
Development of oil and natural gas properties
|
|
(131)
|
|
|
(11)
|
Proceeds from sale of assets
|
|
—
|
|
|
7,692
|
Construction of gathering and transportation assets
|
|
(1,063)
|
|
|
(2,533)
|
Contributions to equity affiliates
|
|
(242)
|
|
|
(2,838)
|
Net cash provided by (used in) investing activities
|
|
(1,436)
|
|
|
2,310
|
Cash flows from financing activities:
|
|
|
|
|
|
Payments for offering costs
|
|
—
|
|
|
(50)
|
Payments for Class C Preferred Unit Exchange
|
|
(238)
|
|
|
—
|
Proceeds from issuance of debt
|
|
4,000
|
|
|
2,000
|
Repayment of debt
|
|
(34,000)
|
|
|
(11,000)
|
Distributions to common unitholders
|
|
(5,216)
|
|
|
(23,243)
|
Class B Preferred Unit cash distributions
|
|
(17,675)
|
|
|
(33,338)
|
Units tendered by SOG employees for tax withholdings
|
|
(218)
|
|
|
—
|
Debt issuance costs
|
|
(1,037)
|
|
|
(1,008)
|
Net cash used in financing activities
|
|
(54,384)
|
|
|
(66,639)
|
Net increase in cash and cash equivalents
|
|
2,165
|
|
|
2,613
|
Cash and cash equivalents, beginning of period
|
|
2,934
|
|
|
321
|
Cash and cash equivalents, end of period
|
$
|
5,099
|
|
$
|
2,934
|
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
Change in accrued capital expenditures
|
$
|
528
|
|
$
|
525
|
Cash paid during the period for income taxes
|
$
|
138
|
|
$
|
—
|
Cash paid during the period for interest
|
$
|
9,159
|
|
$
|
9,763
|
See accompanying notes to consolidated financial statements.
SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES
Consolidated Statements of Changes in Partners’ Capital
(In thousands, except unit data)
|
|
|
|
|
|
|
|
|
Common Units
|
|
Total
|
|
Units
|
|
Amount
|
|
Capital
|
|
|
|
|
|
|
|
|
Partners' Deficit, December 31, 2017
|
14,965,134
|
|
$
|
(29,308)
|
|
$
|
(29,308)
|
Unit-based compensation programs
|
531,561
|
|
|
1,938
|
|
|
1,938
|
Issuance of common units, net of offering costs of $0.1 million
|
989,544
|
|
|
9,585
|
|
|
9,585
|
Cash distributions to common unit holders
|
—
|
|
|
(23,243)
|
|
|
(23,243)
|
Distributions - Class B Preferred Units
|
—
|
|
|
(39,283)
|
|
|
(39,283)
|
Net income
|
—
|
|
|
15,691
|
|
|
15,691
|
Partners' Deficit, December 31, 2018
|
16,486,239
|
|
$
|
(64,620)
|
|
$
|
(64,620)
|
Adoption of accounting standards
|
—
|
|
|
(181)
|
|
|
(181)
|
Preferred unit exchange
|
—
|
|
|
103,773
|
|
|
103,773
|
Unit-based compensation programs
|
1,109,880
|
|
|
1,531
|
|
|
1,531
|
Units tendered by SOG employees for tax withholdings
|
(85,417)
|
|
|
(218)
|
|
|
(218)
|
Common units issued for asset management fee
|
2,576,760
|
|
|
5,228
|
|
|
5,228
|
Cash distributions to common unitholders
|
—
|
|
|
(5,216)
|
|
|
(5,216)
|
Distributions - Class B Preferred Units
|
—
|
|
|
(24,955)
|
|
|
(24,955)
|
Net loss
|
—
|
|
|
(51,142)
|
|
|
(51,142)
|
Partners' Deficit, December 31, 2019
|
20,087,462
|
|
$
|
(35,800)
|
|
$
|
(35,800)
|
See accompanying notes to consolidated financial statements.
SANCHEZ MIDSTREAM PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2019 and 2018
1. ORGANIZATION AND BUSINESS
Organization
We are a growth-oriented publicly-traded limited partnership formed in 2005 focused on the acquisition, development, ownership and operation of midstream and other energy-related assets in North America. We have ownership stakes in oil and natural gas gathering systems, natural gas pipelines, and natural gas processing facilities, all located in the Western Eagle Ford in South Texas. We also own production assets in Texas and Louisiana. We have entered into the Services Agreement with Manager, the sole member of our general partner, pursuant to which Manager provides services we require to conduct our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. On June 2, 2017, we changed our name to Sanchez Midstream Partners LP from Sanchez Production Partners LP. Manager owns our general partner and all of our incentive distribution rights. Our common units are currently listed on the NYSE American under the symbol “SNMP.”
2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Accounting policies used by us conform to accounting principles generally accepted in the United States of America (“GAAP). The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Our business consists of two reportable segments: Production and Midstream. Midstream includes Western Catarina Midstream, the Carnero JV and Seco Pipeline. Production consists of our oil and natural gas properties in Texas and Louisiana. Our management evaluates performance based on these two business segments.
Recent Accounting Pronouncements
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our consolidated financial statements upon adoption.
In August 2018, the FASB issued Accounting Standards Update (“ASU”) 2018-13 “Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements,” which modifies the disclosure requirements on fair value measurements. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. We do not anticipate the adoption of this standard to have a material impact on our consolidated financial statements.
In June 2018, the FASB issued ASU 2018-07 “Compensation - Stock Compensation (Topic 718) - Improvements to Nonemployee Share-Based Payment Accounting,” which expands the scope of Topic 718, “Compensation – Stock Compensation”, to include share-based payment transactions for acquiring goods and services from nonemployees. We adopted this ASU effective January 1, 2019, which resulted in the remeasurement of our outstanding unvested awards as of January 1, 2019 and changed the expense recorded for equity awards going forward. The adoption of this standard resulted in an approximately $0.2 million charge to retained earnings.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in more timely recognition of
losses. Additionally, in November 2019, the FASB issued ASU 2019-10 “Financial Instruments – Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates,” which changed the effective date for certain issuers to annual and interim periods in fiscal years beginning after December 15, 2022, and earlier adoption is permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018. Additionally, in July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842 (Leases),” which provides narrow amendments to clarify how to apply certain aspects of ASU 2016-02. The Partnership elected the practical expedients disclosed in ASU 2018-10. The effective date in ASU 2018-10 is the same as that of ASU 2016-02. The standards update the previous lease guidance by requiring the recognition of a right-of-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. The Partnership adopted this standard effective January 1, 2019. The adoption of this standard did not have a material impact on our consolidated financial statements.
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.
Use of Estimates
The consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of natural gas, NGLs and oil; future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of derivatives; and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best judgment using the data available. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Revenue Recognition
Midstream
We account for revenue from contracts with customers in accordance with ASC 606 and ASC 842 for our midstream segment. The Seco Pipeline Transportation Agreement is our only contract that we account for using ASC 606. Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. As such, we applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. Additionally, Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606. Under this exception, revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved.
The Gathering Agreement (as defined in Note 14 “Related Party Transactions”) was classified as an operating lease at inception and is accounted for under ASC 842, as Sanchez Energy controls the physical use of the property under the lease. Revenues relating to the Gathering Agreement is recognized in the period service is provided. Under this
arrangement, the Partnership receives a fee or fees for services provided. The revenue the Partnership recognizes from gathering and transportation services is generally directly related to the volume of oil and natural gas that flows through its systems.
Production
Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators. We are not party to the contracts with the third-party customers. However, we are party to joint operating agreements, which we account for under ASC 808, and revenues and expenses for these arrangements is recognized based on the information provided to us by the operators.
We additionally recognize and present changes in the fair value of our commodity derivative instruments within natural gas sales and oil sales in the consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging”.
Accounts Receivable, Net
Our accounts receivable are primarily from our contractual agreements with Sanchez Energy and its subsidiaries, operators of our oil and natural gas properties and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. Our allowance for doubtful accounts was $0.4 million as of December 31, 2019 and 2018.
Concentration of Credit Risk and Accounts Receivable
Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our Credit Agreement and maintain an investment grade credit rating. Substantially all of our accounts receivable are due from operators of our oil and natural gas properties. These sales are generally unsecured and, in some cases, may carry a parent guarantee. We routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. We have no off-balance-sheet credit exposure related to our operations or customers.
Sanchez Energy accounted for 86% and 71% of total revenue for the years ended December 31, 2019 and 2018, respectively. We are highly dependent upon Sanchez Energy as our most significant customer, and we expect to derive a substantial portion of our revenue from Sanchez Energy in the foreseeable future. Accordingly, we are indirectly subject to the business risks of Sanchez Energy.
Income Taxes
SNMP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements.
Earnings per Unit
Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss) based on provisions of the Amended Partnership Agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the income for the period had been distributed in accordance with the Amended Partnership Agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income
(loss) per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of the Amended Partnership Agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.
Asset Retirement Obligations
Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, asset life, inflation and the credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset and is included in accretion expense in the our consolidated statements of operations.
To estimate the fair value of an asset retirement obligation, the Partnership employs a present value technique, which reflects certain assumptions, including its credit‑adjusted risk‑free interest rate, inflation rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.
Oil and Natural Gas Properties
We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.
Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described in Note 8 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements, proved reserves estimates are subject to future revisions when additional information becomes available.
All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets.
Estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. Cash flow estimates for the impairment testing are based on third party reserve reports and exclude derivative instruments. Refer to Note 8 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements for additional information.
Reserves of Natural Gas, NGLs and Oil
Our estimate of proved reserves is based on the quantities of natural gas, NGLs and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Management estimates the proved reserves attributable to our ownership based on various factors, including consideration of the reserve report prepared by Ryder Scott, an independent oil and natural gas consulting firm. On an annual basis, our proved reserve estimates and the reserve report prepared by Ryder Scott are reviewed by the Audit Committee and the Board. Our financial statements for 2019 and 2018 were prepared using Ryder Scott’s estimates of our proved reserves.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.
Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the actual quantities of oil and natural gas eventually recovered.
Unit-Based Compensation
The Partnership records unit-based compensation expense for awards granted in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Unit-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method.
Investments
We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within earnings from equity investments in our consolidated statements of operations.
Earnout Derivative
As part of the Carnero Gathering Transaction (defined in Note 12 “Investments”), we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Sanchez Energy and other producers. The earnout derivative is accounted for under ASC 815, and we measure its fair value through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios.
3. REVENUE RECOGNITION
Revenue from Contracts with Customers
We account for revenue from contracts with customers in accordance with ASC 606. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires
that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.
Disaggregation of Revenue
We recognized revenue of $76.6 and $83.6 million for the years ended December 31, 2019 and 2018, respectively. We disaggregate revenue based on type of revenue and product type. In selecting the disaggregation categories, we considered a number of factors, including disclosures presented outside the financial statements, such as in our earnings release and investor presentations, information reviewed internally for evaluating performance, and other factors used by the Partnership or the users of its financial statements to evaluate performance or allocate resources. We have concluded that disaggregating revenue by type of revenue and product type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.
Midstream Segment
The Seco Pipeline Transportation Agreement is the only contract that we account for under ASC 606. The Catarina Midstream Gathering Agreement (as defined in Note 14 “Related Party Transactions”) is classified as an operating lease and is accounted for under ASC 842, “Leases”, and is reported as gathering and transportation lease revenue in our consolidated statements of operations. Both of these contracts are further discussed in Note 14 “Related Party Transactions.”
We account for income from our unconsolidated equity method investments as earnings from equity investments in our consolidated statements of operations. Earnings from these equity method investments are further discussed in Note 12 “Investments.”
Production Segment
Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators. We are not party to the contracts with the third-party customers. However, we are party to joint operating agreements, which we account for under ASC 808 and revenues for these arrangements is recognized based on the information provided to us by the operators.
We additionally recognize and present changes in the fair value of our commodity derivative instruments within natural gas sales and oil sales in the consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging”.
Performance Obligations
Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. We applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. The Seco Pipeline Transportation Agreement requires payment within 30 days following the calendar month of delivery.
The Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606 which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606 have been met. Under this exception, neither estimation of variable consideration nor disclosure of the transaction price allocated to the remaining performance obligations is required. Revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved.
For forms of variable consideration that are not associated with a specific volume (such as late payment fees) and thus do not meet allocation exception, estimation is required. These fees, however, are immaterial to our consolidated financial statements and have a low probability of occurrence. As significant reversals of revenue due to this variability are not probable, no estimation is required.
Contract Balances
Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under ASC 606. At December 31, 2019, and 2018 our accounts receivable from contracts with customers were $1.1 million and $0.6 million, respectively, and are presented within accounts receivable – related entities on the consolidated balance sheets.
4. ACQUISITIONS AND DIVESTITURES
Louisiana Divestiture
In September 2018, we entered into a purchase and sale agreement to sell certain non-operated production assets located in Louisiana for cash consideration of approximately $1.3 million (the “Louisiana Divestiture”). The Louisiana Divestiture closed on October 22, 2018 and we recorded a gain of approximately $0.6 million on the sale.
Briggs Divestiture
In April 2018, we entered into a purchase and sale agreement to sell specified wellbores and related assets and interests in La Salle County Texas (the “Briggs Assets”) for a base purchase price of approximately $4.5 million which, after giving effect to purchase price adjustments, was reduced to approximately $4.2 million in cash consideration (the “Briggs Divestiture”). In addition, other than limited obligations that we retained, the buyer agreed to assume all obligations relating to the Briggs Assets, including all plugging and abandonment costs, that may arise on or after March 1, 2018. The Briggs Divestiture closed on April 30, 2018 and we recorded a gain of approximately $1.8 million on the sale.
Cola Divestiture
In April 2018, we entered into multiple purchase and sale agreements to sell certain non-operated production assets located in Oklahoma for total cash consideration of approximately $1.0 million (collectively, the “Cola Divestiture”). The Cola Divestitures were all closed by May 8, 2018 and we recorded a total gain of approximately $1.1 million on the sale.
5. FAIR VALUE MEASUREMENTS
Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. 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. Fair value measurements are classified and disclosed in one of the following categories:
Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2019
|
|
|
Active Markets for
|
|
Observable
|
|
|
|
|
|
|
|
Identical Assets
|
|
Inputs
|
|
Unobservable Inputs
|
|
|
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Fair Value
|
Commodity derivative instrument
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liability
|
|
$
|
—
|
|
$
|
(759)
|
|
$
|
—
|
|
$
|
(759)
|
Midstream derivative instrument
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnout derivative liability
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
Other liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrant
|
|
|
—
|
|
|
(629)
|
|
|
—
|
|
|
(629)
|
Total
|
|
$
|
—
|
|
$
|
(1,388)
|
|
$
|
—
|
|
$
|
(1,388)
|
The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2018 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2018
|
|
|
Active Markets for
|
|
Observable
|
|
|
|
|
|
|
|
Identical Assets
|
|
Inputs
|
|
Unobservable Inputs
|
|
|
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Fair Value
|
Commodity derivative instrument
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
$
|
—
|
|
$
|
3,914
|
|
$
|
—
|
|
$
|
3,914
|
Midstream derivative instrument
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnout derivative liability
|
|
|
—
|
|
|
—
|
|
|
(5,856)
|
|
|
(5,856)
|
Total
|
|
$
|
—
|
|
$
|
3,914
|
|
$
|
(5,856)
|
|
$
|
(1,942)
|
As of December 31, 2019 and 2018, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature.
Fair Value on a Non-Recurring Basis
The Partnership follows the provisions of Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. We periodically review oil and natural gas properties and related equipment for impairment when facts and circumstances indicate that their carrying values may not be recoverable.
A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 10 ‘‘Asset Retirement Obligation.’’
Class C Preferred Units – As part of the Exchange (defined in Note 17 “Partners’ Capital”), Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and the Warrant in a privately negotiated transaction. The Class C Preferred Units were measured using valuation techniques that convert a future obligation to a single discounted amount. We have therefore classified the fair value measurements of the Class C Preferred units as Level 2 and are presented within “Class C Preferred Units” on the Consolidated Balance Sheets.
Seco Pipeline – We recorded a non-cash impairment charge of $32.1 million to impair the Seco Pipeline. The carrying value of the Seco Pipeline was reduced to a fair value of zero, estimated based on an inputs characteristic of a Level 3 fair value measurement.
The fair value of the Seco Pipeline was measured using probabilistic valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of the Seco Pipeline include estimates of: (i) future operating and development costs; (ii) estimated future cash flows; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change.
Fair Value of Financial Instruments
The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value.
Credit Agreement – We believe that the carrying value of our Credit Agreement (defined in Note 7 “Debt”) approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms. The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties. The Credit Agreement is discussed further in Note 7 “Debt.”
Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate. Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We did not have any interest rate derivatives as of December 31, 2019.
Warrant – As part of the Exchange, the Partnership issued to Stonepeak the Warrant which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Warrant expires on the later of August 2, 2026 or 30 days following the full redemption of the Class C Preferred Units. There is no strike price associated with the exercise of the Warrant. The Warrant is valued using ten percent of the junior securities deemed outstanding and the common unit price as of the balance sheet date. We have therefore classified the fair value measurements of the Warrant as Level 2 and is presented within other liabilities on the consolidated balance sheets.
Earnout Derivative – As part of the Carnero Gathering Transaction (defined in Note 12 “Investments”), we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Sanchez Energy and other producers. The earnout derivative was valued through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios. We have therefore classified the fair value measurements of the earnout derivative as Level 3 inputs.
The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded and earnout derivatives classified as Level 3 in the fair value hierarchy (in thousands):
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2019
|
|
2018
|
Beginning balance
|
|
$
|
(5,856)
|
|
$
|
(6,402)
|
Gain on earnout derivative
|
|
|
5,856
|
|
|
546
|
Ending balance
|
|
$
|
—
|
|
$
|
(5,856)
|
|
|
|
|
|
|
|
Gain included in earnings related to derivatives still held as of December 31, 2019 and December 31, 2018
|
|
$
|
5,856
|
|
$
|
546
|
6. DERIVATIVE AND FINANCIAL INSTRUMENTS
To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never our intention to enter into derivative contracts for speculative trading purposes.
Under Topic 815, “Derivatives and Hedging”, all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included in natural gas sales and oil sales in the consolidated statements of operations.
As of December 31, 2019, we had the following derivative contracts in place, all of which are accounted for as mark-to-market activities:
MTM Fixed Price Swaps – NYMEX (Henry Hub)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended (volume in MMBtu)
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Total
|
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
2020
|
|
105,104
|
|
$
|
2.85
|
|
102,008
|
|
$
|
2.85
|
|
99,136
|
|
$
|
2.85
|
|
96,200
|
|
$
|
2.85
|
|
402,448
|
|
$
|
2.85
|
MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended (volume in Bbls)
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Total
|
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
2020
|
|
52,776
|
|
$
|
53.50
|
|
50,960
|
|
$
|
53.50
|
|
49,224
|
|
$
|
53.50
|
|
47,624
|
|
$
|
53.50
|
|
200,584
|
|
$
|
53.50
|
The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the years ended December 31, 2019 and 2018 (in thousands):
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2019
|
|
2018
|
Beginning fair value of commodity derivatives
|
|
$
|
3,914
|
|
$
|
1,231
|
Net gain (loss) on crude oil derivatives
|
|
|
(4,031)
|
|
|
1,400
|
Net gain (loss) on natural gas derivatives
|
|
|
259
|
|
|
(84)
|
Net settlements paid (received) on derivative contracts:
|
|
|
|
|
|
|
Oil
|
|
|
(807)
|
|
|
1,330
|
Natural gas
|
|
|
(94)
|
|
|
37
|
Ending fair value of commodity derivatives
|
|
$
|
(759)
|
|
$
|
3,914
|
The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain (Loss)
|
|
Years Ended December 31,
|
Derivative Type
|
|
in Income
|
|
2019
|
|
2018
|
Commodity – Mark-to-Market
|
|
Oil sales
|
|
$
|
(4,031)
|
|
$
|
1,400
|
Commodity – Mark-to-Market
|
|
Natural gas sales
|
|
|
259
|
|
|
(84)
|
|
|
|
|
$
|
(3,772)
|
|
$
|
1,316
|
|
|
|
|
|
|
|
|
|
Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently contracted with three counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of December 31, 2019 and 2018, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant.
Earnout Derivative
Refer to Note 5 “Fair Value Measurements”.
7. DEBT
Credit Agreement
We have entered into a credit facility with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (as amended by the Ninth Amendment to Third Amended and Restated Credit Agreement (the “Credit Agreement”). The Credit Agreement provides a quarterly amortizing term loan of $155.0 million (the “Term
Loan”) and a maximum revolving credit amount of $20.0 million (the “Revolving Loan”). The Term Loan and Revolving Loan both have a maturity date of September 30, 2021. Borrowings under the Credit Agreement are secured by various mortgages of both midstream and upstream properties that we own as well as various security and pledge agreements among us, certain of our subsidiaries and the administrative agent.
Borrowings under the Credit Agreement are available for limited direct investment in oil and natural gas properties, midstream properties, acquisitions, and working capital and general business purposes. The Credit Agreement has a sub-limit of up to $2.5 million which may be used for the issuance of letters of credit. Pursuant to the Credit Agreement, the initial aggregate commitment amount under the Term Loan is $155.0 million, subject to quarterly $10.0 million principal and other mandatory prepayments. The initial borrowing base under the Credit Agreement was $235.5 million. The borrowing base is equal to the sum of the rolling four quarter EBITDA of our midstream operations and the amount of distributions received from the Carnero JV multiplied by 4.5 or a lower number dependent upon natural gas volumes flowing through Western Catarina Midstream. Outstanding borrowings in excess of our borrowing base must be repaid within 45 days. As of December 31, 2019, the borrowing base under the Credit Agreement was $235.5 million and we had $150.0 million of debt outstanding, consisting of $145.0 million under the Term Loan and $5.0 million under the Revolving Loan. We are required to make mandatory amortizing payments of outstanding principal on the Term Loan of $10 million per fiscal quarter. The maximum revolving credit amount is $20.0 million leaving us with $15.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of December 31, 2019.
At our election, interest for borrowings under the Credit Agreement are determined by reference to (i) the LIBOR plus an applicable margin between 2.50% and 3.00% per annum based on net debt to EBITDA or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.50% and 2.00% per annum based on net debt to EBITDA plus (iii) a commitment fee of 0.500% per annum based on the unutilized maximum revolving credit. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.
The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions to unitholders.
In addition, we are required to maintain the following financial covenants:
|
·
|
|
current assets to current liabilities of at least 1.0 to 1.0 at all times; and
|
|
·
|
|
senior secured net debt to consolidated adjusted EBITDA for the last twelve months, as of the last day of any fiscal quarter, of not greater than 3.5 to 1.0.
|
The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) our existing general partner ceases to be our sole general partner or (ii) certain specified persons shall cease to own more than 50% of the equity interests of our general partner or shall cease to control our general partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies.
At December 31, 2019, we were in compliance with the financial covenants contained in the Credit Agreement. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our Credit Agreement or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of the Credit Agreement, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted.
Debt Issuance Costs
As of December 31, 2019 and 2018, our unamortized debt issuance costs were approximately $1.2 million and $1.4 million, respectively. These costs are amortized to interest expense in our consolidated statements of operations over the life of our Credit Agreement. Amortization of debt issuance costs recorded during the years ended December 31, 2019 and 2018 were approximately $1.3 million and $0.8 million, respectively.
8. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT
Gathering and transportation assets consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2019
|
|
2018
|
Gathering and transportation assets
|
|
|
|
|
|
|
Midstream assets
|
|
$
|
186,941
|
|
$
|
186,406
|
Less: Accumulated depreciation, amortization and impairment
|
|
|
(74,648)
|
|
|
(34,598)
|
Total gathering and transportation assets, net
|
|
$
|
112,293
|
|
$
|
151,808
|
Oil and natural gas properties consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2019
|
|
2018
|
Oil and natural gas properties and related equipment
|
|
|
|
|
|
|
Proved property
|
|
$
|
112,476
|
|
$
|
112,173
|
Less: Accumulated depreciation, depletion, amortization and impairments
|
|
|
(69,541)
|
|
|
(65,647)
|
Total oil and natural gas properties and equipment, net
|
|
$
|
42,935
|
|
$
|
46,526
|
Oil and Natural Gas Properties. We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties.
Proved Reserves. Accounting rules require that we price our oil and natural gas proved reserves at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place.
Our estimate of proved reserves is based on the quantities of natural gas, NGLs, and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Proved reserves are calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2019 and 2018 is described in detail in Note 20 “Supplemental Information on Oil and Natural Gas Producing Activities.”
Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairments are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.
Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
Depreciation, Depletion and Amortization. Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold and proved property acquisition costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves.
All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets.
Impairment of Oil and Natural Gas Properties and Other Non-Current Assets. Oil and natural gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third-party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Other significant inputs, besides reserves, used to determine the fair values of proved properties include estimates of: (i) future operating and development costs; (ii) future commodity prices; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Cash flow estimates for impairment testing exclude derivative instruments.
Depreciation, depletion and amortization consisted of the following (in thousands):
|
|
|
|
|
|
|
Years Ended
|
|
December 31,
|
|
2019
|
|
2018
|
Depreciation, depletion and amortization of oil and natural gas-related assets
|
$
|
3,942
|
|
$
|
4,798
|
Depreciation and amortization of gathering and transportation related assets
|
|
7,931
|
|
|
7,729
|
Amortization of intangible assets
|
|
13,460
|
|
|
13,460
|
Total Depreciation, depletion and amortization
|
$
|
25,333
|
|
$
|
25,987
|
The recoverability of gathering and transportation assets is evaluated when facts or circumstances indicate that their carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Upon disposition or retirement of gathering and transportation assets, any gain or loss is recorded to operations.
On January 13, 2020, we received a written notice from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective February 12, 2020. For the year ended December 31, 2019, we recorded a non-cash charge of $32.1 million, to impair the Seco Pipeline. For the year ended December 31, 2018, we recorded no impairment charges.
Asset Retirement Obligation. As described in Note 10 “Asset Retirement Obligation,” estimated asset retirement costs are recognized when the asset is acquired or placed in service. Costs associated with oil and natural gas properties
are amortized over proved developed reserves using the units-of-production method. Costs associated with gathering and transportation assets are depreciated using the straight-line method over the useful lives of the asset. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.
Exploration and Dry Hole Costs. Exploration and dry hole costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs and the impairment, amortization and abandonment associated with leases on our unproved properties. All such costs on oil and natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred. We recorded no exploration or dry hole costs for the years ended December 31, 2019 and 2018.
Materials and Supplies. Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of our oil and natural gas properties.
9. PROVISION FOR INCOME TAXES
Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in qualifying income (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2019 and 2018 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income taxes on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner's individual tax basis in our limited partner interests.
Provision for income taxes reflects franchise tax obligations in the state of Texas (the “Texas Margin Tax”). Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.
Our federal and state income tax provision (benefit) is summarized below:
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2019
|
|
2018
|
Current:
|
|
|
|
|
|
|
Federal
|
|
$
|
—
|
|
$
|
—
|
State
|
|
|
328
|
|
|
64
|
Total current
|
|
|
328
|
|
|
64
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
Federal
|
|
|
—
|
|
|
—
|
State
|
|
|
(126)
|
|
|
126
|
Total deferred
|
|
|
(126)
|
|
|
126
|
Total provision for income taxes
|
|
$
|
202
|
|
$
|
190
|
A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income (loss) before income taxes is as follows (in thousands):
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2019
|
|
2018
|
Pre-tax net book income (loss)
|
|
$
|
(50,940)
|
|
$
|
15,881
|
|
|
|
|
|
|
|
Texas Margin Tax (a)
|
|
|
126
|
|
|
267
|
Return to accrual
|
|
|
76
|
|
|
9
|
Valuation allowance
|
|
|
—
|
|
|
(86)
|
Provision for income taxes
|
|
$
|
202
|
|
$
|
190
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
(0.40%)
|
|
|
1.20%
|
|
(a)
|
|
Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.
|
The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2019
|
|
2018
|
Deferred tax assets (liabilities):
|
|
|
|
|
|
|
Derivative assets
|
|
$
|
(23)
|
|
$
|
(15)
|
Depreciable, depletable property, plant and equipment
|
|
|
21
|
|
|
(112)
|
Other
|
|
|
2
|
|
|
1
|
Deferred tax assets (liabilities):
|
|
|
—
|
|
|
(126)
|
Valuation allowance
|
|
|
—
|
|
|
—
|
Total deferred tax assets (liabilities)
|
|
$
|
—
|
|
$
|
(126)
|
Deferred tax assets which required valuation allowances were related to assets sold in 2018. Therefore, the valuation allowance is no longer necessary and was removed as of December 31, 2018.
As of December 31, 2019 and 2018, the Partnership had no material uncertain tax positions.
The Partnership files income tax returns in the U.S. and various state jurisdictions. The Partnership is no longer subject to examination by federal income tax authorities prior to 2016. State statutes vary by jurisdiction.
10. ASSET RETIREMENT OBLIGATION
We recognize the fair value of a liability for an ARO in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities or gathering and transportation assets. Subsequently, the ARC is depreciated using the units-of-production method for production assets and the straight-line method for midstream assets. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells and decommissioning of oil and natural gas gathering and other facilities.
Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas properties, equipment and facilities or gathering and transportation assets.
The following table is a reconciliation of the ARO (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2019
|
|
2018
|
Asset retirement obligation, beginning balance
|
|
$
|
6,200
|
|
$
|
6,074
|
Liabilities added from escalating working interests
|
|
|
172
|
|
|
288
|
Sales
|
|
|
—
|
|
|
(613)
|
Revisions to cost estimates
|
|
|
—
|
|
|
(46)
|
Accretion expense
|
|
|
526
|
|
|
497
|
Asset retirement obligation, ending balance
|
|
$
|
6,898
|
|
$
|
6,200
|
Additional AROs increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Abandonments of oil and natural gas wells and other facilities reduce the liability for AROs. In 2019 and 2018, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. During the year ended December 31, 2018, obligations were sold as part of the Briggs Divestiture, Louisiana Divestiture and Cola Divestiture.
11. INTANGIBLE ASSETS
Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $145.2 million related to the Gathering Agreement with Sanchez Energy that was entered into as part of the Western Catarina Midstream transaction. Pursuant to the 15-year agreement, Sanchez Energy tenders all of its crude oil, natural gas and other hydrocarbon-based product volumes on 35,000 dedicated acres in the Western Catarina of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with a right to tender additional volumes outside of the dedicated acreage. These intangible assets are being amortized using the straight-line method over the 15 year life of the agreement.
Amortization expense for the years ended December 31, 2019 and 2018 was $13.5 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations. Intangible assets as of December 31, 2019 and 2018 are detailed below (in thousands):
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2019
|
|
2018
|
Beginning balance
|
|
$
|
158,706
|
|
$
|
172,166
|
Amortization
|
|
|
(13,460)
|
|
|
(13,460)
|
Ending balance
|
|
$
|
145,246
|
|
$
|
158,706
|
12. INVESTMENTS
In July 2016, we completed a transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Gathering, LLC (“Carnero Gathering”), a joint venture that was 50% owned and operated by Targa Resources Corp. (NYSE: TRGP) (“Targa”), for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the acquisition date (the “Carnero Gathering Transaction”). The fair value of the intangible asset for the contractual customer relationship related to Carnero Gathering was valued at approximately $13.0 million. This amount is being amortized over a contract term of 15 years and decreases earnings from equity investments in our consolidated statements of operations. As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Sanchez Energy and other producers. See Note 5 “Fair Value Measurements” for further discussion of the earnout derivative.
In November 2016, we completed a transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Processing, LLC (“Carnero Processing”), a joint venture that was 50% owned and operated by Targa, for aggregate cash consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition (the “Carnero Processing Transaction”).
In May 2018, we executed a series of agreements with Targa and other parties pursuant to which, among other things: (1) the parties merged their respective 50% interests in Carnero Gathering and Carnero Processing (the “Carnero JV Transaction”) to form an expanded 50 / 50 joint venture in South Texas, within Carnero G&P, LLC (“the Carnero JV”), (2) Targa contributed 100% of the equity interest in the Silver Oak II Gas Processing Plant (“Silver Oak II”), located in Bee County Texas, to the Carnero JV, which expands the processing capacity of the Carnero JV from 260 MMcf/d to 460 MMcf/d, (3) Targa contributed certain capacity in the 45 miles of high pressure natural gas gathering pipelines owned by Carnero Gathering that connect Western Catarina Midstream to nearby pipelines and the Raptor Gas Processing Facility (the “Carnero Gathering Line”) to the Carnero JV resulting in the Carnero JV owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, (4) the Carnero JV received a new dedication from Sanchez Energy and its working interest partners of over 315,000 acres located in the Western Eagle Ford on Sanchez Energy’s Comanche Asset pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Sanchez Energy, which was approved by all of the unaffiliated Comanche working interest partners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the Carnero JV limited by the capacity of the Raptor Gas Processing Facility. As a result of the Carnero JV Transaction we now record our share of earnings and losses from the Carnero JV using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if the Carnero JV were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our consolidated statements of operations. In the event of liquidation of the Carnero JV, available proceeds are first distributed to any priority return and unpaid capital associated with Silver Oak II, and then to members in accordance with their capital accounts.
As of December 31, 2019, the Partnership had paid approximately $124.1 million for its investment in the Carnero JV related to the initial payments and contributed capital. The Partnership has accounted for this investment using the equity method. Targa is the operator of the Carnero JV and has significant influence with respect to the normal day-to-day capital and operating decisions. We have included the investment balance in the equity investments caption on our consolidated balance sheets. For the year ended December 31, 2019, the Partnership recorded earnings of approximately $4.0 million in equity investments from the Carnero JV, which was offset by approximately $1.2 million related to the amortization of the contractual customer intangible asset. We have included these equity method earnings in the earnings from equity investments line within the consolidated statements of operations. Cash distributions of approximately $17.2 million were received during the year ended December 31, 2019.
Summarized financial information of unconsolidated entities is as follows (in thousands):
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2019
|
|
2018
|
Sales
|
|
$
|
159,508
|
|
$
|
321,607
|
Total expenses
|
|
|
145,837
|
|
|
290,073
|
Net income
|
|
$
|
13,671
|
|
$
|
31,534
|
13. COMMITMENTS AND CONTINGENCIES
As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Sanchez Energy and other producers. This earnout has an approximate value of zero as of December 31, 2019. For the year ended December 31, 2019 payments totaling approximately $32.0 thousand were made. For the year ended December 31, 2018, natural gas received did not exceed the threshold.
14. RELATED PARTY TRANSACTIONS
Sanchez-Related Agreements
We are controlled by our general partner. The sole member of our general partner is Manager, which has no officers. The sole manager and member of Manager is SP Capital Holdings, LLC, which has no officers. The co-managers of SP
Capital Holdings, LLC are Antonio R. Sanchez, III, a member of and Chairman of the Board; Eduardo A. Sanchez, a member of the Board; Patricio D. Sanchez, a member of the Board and the President and Chief Operating Officer of our general partner; and their father, Antonio R. Sanchez, Jr. SP Capital Holdings, LLC is owned by Antonio R. Sanchez, III, Eduardo A. Sanchez , and Patricio D. Sanchez, along with their sister, Ana Lee Sanchez Jacobs, and Antonio R. Sanchez, Jr. In May 2014, we entered into the Services Agreement with Manager pursuant to which Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, and acquisition, disposition and financing services. In connection with providing services under the Services Agreement, Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Each of these fees, not including the reimbursement of costs, is paid in cash unless Manager elects for such fee to be paid in our equity with the exception of the following modified payment terms under the Services Agreement. In November 2019, a letter agreement was executed modifying the payment terms under the Services Agreement beginning with the fee for the quarter ended September 30, 2019. Under the modified terms, payment is being withheld until such time as all issued and outstanding Class C Units have been redeemed. Following the redemption of all issued and outstanding Class C Units the fee will be paid in our equity. As of December 31, 2019, the amount owed under the Services Agreement was $4.9 million and is presented within long term accrued liabilities - related entities on the consolidated balance sheet. If all Class C Units had been redeemed on December 31, 2019, we would issue approximately 11.4 million common units to Manager to settle the portion of the liability related to the November 2019 letter agreement. During the years ended December 31, 2019 and 2018, we incurred costs of approximately $7.3 million and $8.6 million, respectively, to Manager under the Services Agreement. Manager utilizes SOG to provide the services under the Services Agreement. The Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless both Manager and the Partnership provide notice of termination to the other with at least 180 days’ notice.
SOG, headquartered in Houston, Texas, is a private full-service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates. SOG has successfully built and operated extensive midstream and gathering assets associated with its aforementioned development activities. The Chairman of the Board, Antonio R. Sanchez, III, the President and Chief Operating Officer of our general partner as well as one of our directors, Patricio D. Sanchez, one of our directors, Eduardo A. Sanchez, along with their immediate family members Ana Lee Sanchez Jacobs and Antonio R. Sanchez, Jr., collectively, either directly or indirectly, own a majority of the equity interests of SOG. In addition, Antonio R. Sanchez, III and Patricio D. Sanchez are Co-Presidents of SOG; Antonio R. Sanchez, Jr. is the Chief Executive Officer and sole director of SOG; Ana Lee Sanchez Jacobs is an Executive Vice President of SOG; and Gerald F. Willinger is an Executive Vice President of SOG.
Sanchez-Related Transactions
We have entered into several transactions with Sanchez Energy since January 1, 2018.
In conjunction with the acquisition of Western Catarina Midstream, we entered into a 15-year gas gathering agreement with Sanchez Energy, pursuant to which Sanchez Energy agreed to tender all of its crude oil, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres in the Western Catarina area of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”). During the first five years of the term of the Gathering Agreement, Sanchez Energy is required to meet a minimum quarterly volume delivery commitment of 10,200 Bbls per day of oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. Sanchez Energy is required to pay gathering and processing fees of $0.96 per Bbl for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through Western Catarina Midstream, in each case, subject to an annual escalation for a positive increase in the consumer price index. On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by Sanchez Energy based on water that is delivered through the gathering system through March 31, 2018, and have subsequently agreed to continue the incremental infrastructure fee on a month-to-month basis. For the years ended December 31, 2019 and 2018, Sanchez Energy paid us approximately $59.1 million and $57.9 million, respectively, pursuant to the terms of the gathering and processing agreement.
As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. For the year ended December 31, 2019, payments totaling approximately $32.0 thousand were made. For the year ended December 31, 2018, natural gas did not exceed the threshold.
In September 2017, we entered into the Seco Pipeline Transportation Agreement. For the years ended December 31, 2019 and 2018, Sanchez Energy paid us approximately $6.8 million and $7.2 million, respectively, pursuant to the terms of that agreement. On January 13, 2020, we received a written notice from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective February 12, 2020.
In May 2018, the Carnero JV, which is operated by Targa, received a dedication from Sanchez Energy and its working interest partners of over 315,000 acres located in the Western Eagle Ford on Sanchez Energy’s Comanche Asset pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Sanchez Energy, which was approved by all of the unaffiliated Comanche working interest partners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the joint ventures limited by the capacity of the Raptor Gas Processing Facility.
As of December 31, 2019 and 2018, the Partnership had a net receivable from related parties of approximately $6.7 million, respectively, which are included in accounts receivable – related entities in the consolidated balance sheets. As of December 31, 2019 and 2018, the Partnership also had a net payable to related parties of approximately $5.5 million, and $5.6 million, respectively. The net receivable/payable as of December 31, 2019 consist primarily of revenues receivable from oil and natural gas production and transportation, offset by costs associated with that production and transportation.
Sanchez Energy is an independent exploration and production company focused on the acquisition and development of U.S. onshore unconventional oil and natural gas resources, with a current focus on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas where it has assembled approximately 415,000 gross leasehold acres (215,000 net acres). The Chairman of the Board, Antonio R. Sanchez, III, is Sanchez Energy’s Chief Executive Officer and a member of its board of directors. A member of the Board, Eduardo A. Sanchez, is the former President of Sanchez Energy. The President and Chief Operating Officer of our general partner, Patricio D. Sanchez, who is also a member of the Board, is an Executive Vice President of Sanchez Energy. Antonio R. Sanchez, Jr., the father of Antonio R. Sanchez, III, Eduardo A. Sanchez, and Patricio D. Sanchez, is the Executive Chairman of the board of directors of Sanchez Energy. Antonio R. Sanchez, Jr., Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez beneficially own 6.1%, 3.0%, 1.1% and 1.2%, respectively, of Sanchez Energy’s shares outstanding as of March 13, 2020. As of March 13, 2020, Sanchez Energy indirectly, through one of its wholly owned subsidiaries, beneficially owns approximately 11.4% of the outstanding common units of SNMP. The employees of SOG, including Kirsten A. Hink, our Chief Accounting Officer, provide services to both us and Sanchez Energy.
15. UNIT-BASED COMPENSATION
The Sanchez Midstream Partners LP Long-Term Incentive Plan allows for restricted common unit grants. Restricted common unit activity under the Plan during the period is presented in the following table:
As of December 31, 2019, 840,811 common units remained available for future issuance to participants under the LTIP.
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
Average
|
|
|
Number of
|
|
Grant Date
|
|
|
Restricted
|
|
Fair Value
|
|
|
Units
|
|
Per Unit
|
Outstanding at December 31, 2017
|
|
283,138
|
|
$
|
14.64
|
Granted
|
|
622,534
|
|
|
11.94
|
Vested
|
|
(301,005)
|
|
|
13.60
|
Returned/Cancelled
|
|
(90,973)
|
|
|
12.77
|
Outstanding at December 31, 2018
|
|
513,694
|
|
$
|
12.31
|
Granted
|
|
1,129,173
|
|
|
2.35
|
Vested
|
|
(382,690)
|
|
|
8.50
|
Returned/Cancelled
|
|
(104,710)
|
|
|
12.04
|
Outstanding at December 31, 2019
|
|
1,155,467
|
|
$
|
3.86
|
In April 2019, the Partnership issued 137,613 restricted common units pursuant to the LTIP to certain directors of the Partnership’s general partner that vested immediately on the date of grant. In March 2019, the Partnership issued 991,560 restricted common units pursuant to the LTIP to certain officers and directors of the Partnership’s general partner that vest over three years from the date of grant. The unit-based compensation expense for the awards was based on the fair value on the day before the grant date.
In April 2018, the Partnership issued 63,630 restricted common units pursuant to the LTIP to certain directors of the Partnership’s general partner that vested immediately on the date of grant. In April 2018, the Partnership issued 244,813 and 314,091 restricted common units pursuant to the LTIP to executives that vest on the first anniversary of the date of grant and to non-executive employees that vest over three years from the date of grant, respectively.
16. DISTRIBUTIONS TO UNITHOLDERS
The table below reflects the payment of cash distributions on common units relating to the years ended December 31, 2019 and 2018.
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
Date of
|
|
Date of
|
|
Date of
|
Three months ended
|
|
per unit
|
|
declaration
|
|
record
|
|
distribution
|
March 31, 2018
|
|
$
|
0.4508
|
|
May 8, 2018
|
|
May 22, 2018
|
|
May 31, 2018
|
June 30, 2018
|
|
$
|
0.4508
|
|
August 8, 2018
|
|
August 21, 2018
|
|
August 31, 2018
|
September 30, 2018
|
|
$
|
0.1500
|
|
November 9, 2018
|
|
November 20, 2018
|
|
November 30, 2018
|
December 31, 2018
|
|
$
|
0.1500
|
|
February 7, 2019
|
|
February 20, 2019
|
|
February 28, 2019
|
March 31, 2019
|
|
$
|
0.1500
|
|
May 3, 2019
|
|
May 22, 2019
|
|
May 31, 2019
|
The table below reflects the payment of distributions on Class B Preferred Units relating to the years ended December 31, 2019 and 2018.
|
|
|
|
|
|
|
|
|
|
|
|
Cash distribution
|
|
Date of
|
|
Date of
|
|
Date of
|
Three months ended
|
|
per unit
|
|
declaration
|
|
record
|
|
distribution
|
March 31, 2018
|
|
$
|
0.28225
|
|
May 8, 2018
|
|
May 22, 2018
|
|
May 31, 2018
|
June 30, 2018 (a)
|
|
$
|
0.22580
|
|
August 8, 2018
|
|
August 21, 2018
|
|
August 31, 2018
|
September 30, 2018
|
|
$
|
0.28225
|
|
November 9, 2018
|
|
November 20, 2018
|
|
November 30, 2018
|
December 31, 2018
|
|
$
|
0.28225
|
|
February 7, 2019
|
|
February 20, 2019
|
|
February 28, 2019
|
March 31, 2019
|
|
$
|
0.28225
|
|
May 3, 2019
|
|
May 22, 2019
|
|
May 31, 2019
|
|
(a)
|
|
The Partnership elected to pay the second-quarter 2018 distribution on the Class B Preferred Units in part cash and part in Class B Preferred PIK Units. Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B Preferred Unit and an aggregate distribution of 310,009 Class B Preferred PIK Units, which was paid on August 31, 2018 to holders of record on August 21, 2018.
|
On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units (the “Class C Preferred Units”). Following the Exchange, no distribution was declared with respect to the Class B Preferred Units.
The table below reflects the payment of distributions on Class C Preferred Units related to the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
Class C Preferred
|
|
Date of
|
|
Date of
|
|
Date of
|
Three months ended
|
|
PIK distribution
|
|
declaration
|
|
record
|
|
distribution
|
June 30, 2019
|
|
|
939,327
|
|
August 8, 2019
|
|
August 20, 2019
|
|
August 30, 2019
|
September 30, 2019
|
|
|
1,007,820
|
|
October 30, 2019
|
|
November 29, 2019
|
|
November 20, 2019
|
December 31, 2019
|
|
|
1,039,314
|
|
February 13, 2020
|
|
February 28, 2020
|
|
February 20, 2020
|
17. PARTNERS’ CAPITAL
Outstanding Units
As of December 31, 2019, we had no Class B Preferred Units outstanding, 33,258,043 Class C Preferred Units outstanding and 20,087,462 common units outstanding, which included 1,155,467 unvested restricted common units issued under the LTIP.
Common Unit Issuances
The following table shows the common units issued by the Partnership in 2018 and 2019 to SP Holdings in connection with providing services under the Services Agreement:
|
|
|
|
|
|
|
Common
|
|
Date of
|
Three months ended
|
|
units
|
|
issuance
|
December 31, 2017
|
|
210,978
|
|
March 15, 2018
|
March 31, 2018
|
|
220,214
|
|
May 31, 2018
|
June 30, 2018
|
|
224,342
|
|
September 10, 2018
|
September 30, 2018
|
|
334,010
|
|
November 30, 2018
|
December 31, 2018
|
|
787,750
|
|
March 8, 2019
|
March 31, 2019
|
|
887,269
|
|
May 23, 2019
|
June 30, 2019
|
|
901,741
|
|
August 2, 2019
|
Class B Preferred Unit Offering
On October 14, 2015, pursuant to that certain Class B Preferred Unit Purchase Agreement dated September 25, 2015 between the Partnership and Stonepeak, the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a privately negotiated transaction for an aggregate cash purchase price of $18.00 per Class B Preferred Unit, which resulted in gross proceeds to the Partnership of $350.0 million. The Partnership used the net proceeds to pay a portion of the consideration for the Catarina Transaction, along with the payment to Stonepeak of a fee equal to 2.25% of the consideration paid for the Class B Preferred Units.
Under the terms of our partnership agreement, holders of the Class B Preferred Units received a quarterly distribution, at the election of the Board, of 10.0% per annum if paid in full in cash or 12.0% per annum if paid in part cash (8.0% per annum) and in part Class B Preferred PIK Units (4.0% per annum), as defined in the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement”). Distributions were to be paid on or about the last day of each of February, May, August and November after the end of each quarter.
In accordance with the partnership agreement, on December 6, 2016, we issued an additional 9,851,996 Class B Preferred Units to Stonepeak. On January 25, 2017, the Partnership and Stonepeak entered into a Settlement Agreement and Mutual Release (the “Settlement Agreement”) to settle a dispute arising from the calculation of an adjustment to the number of Class B Preferred Units pursuant to Section 5.10(g) of the Amended Partnership Agreement. Pursuant to the Settlement Agreement, and in accordance with Section 5.4 of the Amended Partnership Agreement, the Partnership issued 1,704,446 Class B Preferred Units to Stonepeak in a privately negotiated transaction as partial consideration for the Settlement Agreement, with the “Class B Preferred Unit Price” being established at $11.29 per Class B Preferred Unit. Pursuant to the terms of the Amended Partnership Agreement, the Class B Preferred Units were convertible at any time, at the option of Stonepeak, into common units of the Partnership, subject to the requirement to convert a minimum of $17.5 million of Class B Preferred Units. The issuance of the Class B Preferred Units pursuant to the Settlement Agreement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof.
The Partnership elected to pay the second-quarter 2018 distribution on the Class B Preferred Units in part cash and part Class B Preferred PIK Units in accordance with the partnership agreement. Accordingly, the Partnership issued 310,009 Class B Preferred PIK Units on August 31, 2018, to Stonepeak.
The Class B Preferred Units are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following (in thousands):
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2019
|
|
2018
|
Mezzanine equity, beginning balance
|
|
$
|
349,857
|
|
$
|
343,912
|
Amortization of discount
|
|
|
1,708
|
|
|
2,358
|
Distributions
|
|
|
23,247
|
|
|
36,925
|
Distributions paid
|
|
|
(17,675)
|
|
|
(33,338)
|
Class B Preferred Unit exchange
|
|
|
(357,137)
|
|
|
—
|
Mezzanine equity, ending balance
|
|
$
|
—
|
|
$
|
349,857
|
On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”).
Class C Preferred Units
On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and the Warrant in a privately negotiated transaction (the “Exchange”). In connection with the Exchange, the Partnership entered into (i) the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement) to set forth the terms of the Class C Preferred Units, (ii) the Amended and Restated Registration Rights Agreement with Stonepeak relating to the registered resale of common units issuable upon the exercise of the Warrant, and (iii) the Amended and Restated Board Representation and Standstill Agreement with Stonepeak.
Under the terms of the Amended Partnership Agreement, commencing with the quarter ended on September 30, 2019, the holders of the Class C Preferred Units will receive a quarterly distribution of 12.5% per annum payable in cash. To the extent that Available Cash (as defined in the Amended Partnership Agreement) is insufficient to pay the distribution in cash, all or a portion of the distribution may be paid in Class C Preferred PIK Units. Commencing with the quarter ending March 31, 2022, the distribution rate will increase to 14% per annum. Distributions are to be paid on or about the last day of each of February, May, August and November following the end of each quarter and are charged to interest expense in our consolidated statements of operations.
The Exchange was accounted for as an extinguishment with the difference between the book value of the redeemed instrument and the fair value of the new instrument being considered a deemed contribution to common equity of approximately $103.8 million. The Class C Preferred Units are accounted for as a long-term liability on the consolidated balance sheet consisting of the following (in thousands):
|
|
|
|
|
|
December 31,
|
|
|
2019
|
Class C Preferred Units
|
|
|
|
Private placement of Class C Preferred Units
|
|
$
|
353,500
|
Discount
|
|
|
(104,250)
|
Amortization of discount
|
|
|
13,129
|
Distributions
|
|
|
19,309
|
Class C Preferred Units, ending balance
|
|
$
|
281,688
|
Warrant
On August 2, 2019, in connection with the Exchange, the Partnership issued to Stonepeak the Warrant which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Warrant expires on the later of August 2, 2026 or 30 days following the full redemption of the Class C Preferred Units. There is no strike price associated with the exercise of the Warrant. The Warrant is accounted for as a liability in accordance with ASC 480 and is presented within other liabilities on the consolidated balance sheet. Changes in the fair value of the Warrant are charged to interest expense in our consolidated statements of operations.
Earnings per Unit
Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss), based on the provisions of the Amended Partnership Agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the net income for the period had been distributed in accordance with the Amended Partnership Agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of the Amended Partnership Agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.
The Partnership’s general partner does not have an economic interest in the Partnership and, therefore, does not participate in the Partnership’s net income.
18. REPORTING SEGMENTS
“Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reporting segments are based on the nature of the operations that are undertaken by each segment. The Midstream segment operates the gathering, processing and transportation of natural gas, NGLs and crude oil. The Production segment operates to produce crude oil and natural gas. These segments are broadly understood across the petroleum and petrochemical industries.
These functions have been defined as the operating segments of the Partnership because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Partnership’s chief operating decision maker (“CODM”) to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available. Operating segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income, which is defined as segment operating revenues less expenses.
The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2019
|
|
2018
|
|
Production
|
|
Midstream
|
|
Production
|
|
Midstream
|
Segment revenues
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
$
|
683
|
|
$
|
—
|
|
$
|
953
|
|
$
|
—
|
Oil sales
|
|
9,512
|
|
|
—
|
|
|
21,272
|
|
|
—
|
Natural gas liquid sales
|
|
539
|
|
|
—
|
|
|
1,709
|
|
|
—
|
Gathering and transportation sales
|
|
—
|
|
|
6,825
|
|
|
—
|
|
|
6,651
|
Gathering and transportation lease revenues
|
|
—
|
|
|
59,090
|
|
|
—
|
|
|
53,025
|
Total segment revenues
|
|
10,734
|
|
|
65,915
|
|
|
23,934
|
|
|
59,676
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating costs
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
5,879
|
|
|
1,499
|
|
|
6,719
|
|
|
1,145
|
Transportation operating expenses
|
|
—
|
|
|
11,553
|
|
|
—
|
|
|
12,316
|
Production taxes
|
|
621
|
|
|
—
|
|
|
1,104
|
|
|
—
|
Gain on sale of assets
|
|
—
|
|
|
—
|
|
|
(3,186)
|
|
|
—
|
Depreciation, depletion and amortization
|
|
3,942
|
|
|
21,391
|
|
|
4,798
|
|
|
21,189
|
Asset impairments
|
|
—
|
|
|
32,119
|
|
|
—
|
|
|
—
|
Accretion expense
|
|
200
|
|
|
326
|
|
|
198
|
|
|
299
|
Total segment operating costs
|
|
10,642
|
|
|
66,888
|
|
|
9,633
|
|
|
34,949
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment other income
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from equity investments
|
|
—
|
|
|
2,831
|
|
|
—
|
|
|
12,859
|
Total segment other income
|
|
—
|
|
|
2,831
|
|
|
—
|
|
|
12,859
|
Segment operating income
|
$
|
92
|
|
$
|
1,858
|
|
$
|
14,301
|
|
$
|
37,586
|
|
|
|
|
|
|
|
Years Ended
|
|
December 31,
|
|
2019
|
|
2018
|
Reconciliation of segment operating income to net income (loss)
|
|
|
|
|
|
Total production operating income
|
$
|
92
|
|
$
|
14,301
|
Total midstream operating income
|
|
1,858
|
|
|
37,586
|
Total segment operating income
|
|
1,950
|
|
|
51,887
|
|
|
|
|
|
|
General and administrative expense
|
|
(17,610)
|
|
|
(23,653)
|
Unit-based compensation expense
|
|
(1,351)
|
|
|
(1,938)
|
Interest expense, net
|
|
(39,789)
|
|
|
(10,961)
|
Other income
|
|
5,860
|
|
|
546
|
Income tax expense
|
|
(202)
|
|
|
(190)
|
Net income (loss)
|
$
|
(51,142)
|
|
$
|
15,691
|
The following table summarizes the total assets and capital expenditures by operating segment as of December 31, 2019 and 2018 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
Production
|
|
Midstream
|
|
Corporate (a)
|
|
Total
|
Other financial information
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
45,550
|
|
$
|
362,961
|
|
$
|
5,929
|
|
$
|
414,440
|
Capital expenditures(b)
|
|
$
|
130
|
|
$
|
775
|
|
$
|
—
|
|
$
|
905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
Production
|
|
Midstream
|
|
Corporate (a)
|
|
Total
|
Other financial information
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
53,556
|
|
$
|
429,523
|
|
$
|
3,606
|
|
$
|
486,685
|
Capital expenditures(b)
|
|
$
|
11
|
|
$
|
4,856
|
|
$
|
—
|
|
$
|
4,867
|
|
(a)
|
|
Corporate assets not reviewed by the CODM on a segment basis consists of cash, certain prepaid expenses, office furniture and other assets.
|
|
(b)
|
|
Inclusive of capital contributions made to equity method investments.
|
Revenue from Sanchez Energy earned in our Midstream segment accounted for 86% and 71% of total revenue for the years ended December 31, 2019 and 2018, respectively. Because all remaining production properties are non-operated, there are no customers in the Production segment that exceed 10% of the Partnership’s consolidated revenue.
19. VARIABLE INTEREST ENTITIES
The Partnership’s investment in the Carnero JV represents a variable interest entity (“VIE”) that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from the Carnero JV is limited to the capital investment of approximately $100.3 million.
As of December 31, 2019, the Partnership had invested approximately $124.1 million in the Carnero JV and no debt has been incurred by the Carnero JV. We have included this VIE in other assets, equity investments on the balance sheet.
Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Partnership’s maximum exposure to loss as of December 31, 2019 and 2018 (in thousands):
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2019
|
|
2018
|
Acquisitions, earnout and capital investments
|
|
$
|
128,140
|
|
$
|
127,899
|
Earnings in equity investments
|
|
|
25,976
|
|
|
23,144
|
Distributions received
|
|
|
(53,805)
|
|
|
(36,578)
|
Maximum exposure to loss
|
|
$
|
100,311
|
|
$
|
114,465
|
20. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
The Supplementary Information on Oil and Natural Gas Producing Activities is presented as required by the appropriate authoritative guidance. The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred for the acquisition of oil and natural gas producing activities, exploration and development activities and the results of operations from oil and natural gas producing activities.
Supplemental information is also provided for per unit production costs; oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved reserves and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved reserves.
Costs
The following table sets forth our capitalized costs as of December 31, 2019 and 2018 (in thousands):
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2019
|
|
2018
|
Capitalized costs at the end of the period:⁽ᵃ⁾
|
|
|
|
|
|
|
Oil and natural gas properties and related equipment (successful efforts method)
|
|
|
|
|
|
|
Proved property
|
|
$
|
112,476
|
|
$
|
112,173
|
Less: Accumulated depreciation, depletion, amortization and impairments
|
|
|
(69,541)
|
|
|
(65,647)
|
Oil and natural gas properties and equipment, net
|
|
$
|
42,935
|
|
$
|
46,526
|
|
(a)
|
|
Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.
|
The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2019 and 2018 (in thousands):
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2019
|
|
2018
|
Costs incurred for the period:
|
|
|
|
|
|
|
Acquisition of properties
|
|
|
|
|
|
|
Proved
|
|
$
|
—
|
|
$
|
—
|
Development costs
|
|
|
131
|
|
|
11
|
Oil and natural gas properties and equipment, net
|
|
$
|
131
|
|
$
|
11
|
|
|
|
|
|
|
|
The development costs for the years ended December 31, 2019 and 2018 primarily represent costs related to recompletions.
We had no exploration and dry hole costs in 2019 and 2018.
Results of Operations
The revenues and expenses associated directly with oil and natural gas producing activities are reflected in the Consolidated Statements of Operations. All of our oil and natural gas producing activities are located in the United States.
Net Proved Reserves of Natural Gas, NGLs and Oil
The following table sets forth information with respect to changes in proved developed and undeveloped reserves. This information excludes reserves related to royalty and net profit interests. All of our reserves are located in the United States.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Total
|
|
Oil
|
|
Natural Gas
|
|
Liquids
|
|
|
(MMBoe)
|
|
(in MMBoe)
|
|
(in MMBoe)
|
|
(in MMBoe)
|
Net proved reserves
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
5,265
|
|
3,246
|
|
1,109
|
|
910
|
Sales of reserves in place
|
|
(1,105)
|
|
(272)
|
|
(322)
|
|
(511)
|
Revisions of previous estimates
|
|
(268)
|
|
(199)
|
|
(261)
|
|
192
|
Production
|
|
(439)
|
|
(296)
|
|
(72)
|
|
(71)
|
December 31, 2018
|
|
3,453
|
|
2,479
|
|
454
|
|
520
|
Sales of reserves in place
|
|
—
|
|
—
|
|
—
|
|
—
|
Revisions of previous estimates
|
|
(145)
|
|
(10)
|
|
(67)
|
|
(68)
|
Production
|
|
(309)
|
|
(228)
|
|
(39)
|
|
(42)
|
December 31, 2019
|
|
2,999
|
|
2,241
|
|
348
|
|
410
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
3,453
|
|
2,479
|
|
454
|
|
520
|
December 31, 2019
|
|
2,999
|
|
2,241
|
|
348
|
|
410
|
Reserves and Related Estimates
Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.
Our year end December 31, 2019 and 2018, proved reserve estimates were 3.0 MMBoe and 3.5 MMBoe, respectively. Reserve estimates for those periods were prepared by, Ryder Scott, an independent petroleum engineering firm, and are used for the applicable disclosures in our financial statements.
Our 2019 estimates of total proved reserves decreased 0.5 MMBoe from 2018 due to production of 0.3 MMBoe and revisions of previous estimates of 0.2 MMBoe. For proved reserves, the production weighted average product price over
the remaining lives of the properties used in our reserve report were: $59.55 per Bbl for oil, $13.68 per Bbl for NGLs and $2.66 per Mcf for natural gas.
Our 2018 estimates of total proved reserves decreased 1.8 MMBoe from 2017 primarily due to a decrease in reserves of 1.1 MMBoe due to the Louisiana Divestiture, Briggs Divestiture and Cola Divestiture. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $66.95 per Bbl for oil, $23.00 per Bbl for NGLs and $3.21 per Mcf for natural gas.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves, Including a Reconciliation of Changes Therein
The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and natural gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.
Future cash inflows are calculated by applying the SEC-required prices of oil and natural gas relating to our proved reserves to the year-end quantities of those reserves. Future cash inflows exclude the impact of our hedging program. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because the Partnership is a non-taxable entity.
The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present values. In addition, variations from expected production rates could result directly or indirectly from factors outside of our control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands):
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2019
|
|
2018
|
Future cash inflows
|
|
$
|
144,628
|
|
$
|
186,675
|
Future production costs
|
|
|
(80,007)
|
|
|
(99,187)
|
Future estimated development costs
|
|
|
(3,400)
|
|
|
(4,043)
|
Future net cash flows
|
|
|
61,221
|
|
|
83,445
|
10% annual discount for estimated timing of cash flows
|
|
|
(22,871)
|
|
|
(31,199)
|
Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves
|
|
$
|
38,350
|
|
$
|
52,246
|
The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands):
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2019
|
|
2018
|
Beginning of the period
|
|
$
|
52,246
|
|
$
|
56,697
|
Sales and transfers of oil and natural gas, net of production costs
|
|
|
(8,006)
|
|
|
(14,795)
|
Net changes in prices and production costs related to future production
|
|
|
(7,330)
|
|
|
17,392
|
Changes in development costs
|
|
|
35
|
|
|
207
|
Revisions of previous quantity estimates
|
|
|
(1,942)
|
|
|
(4,203)
|
Purchases and sales of reserves in place
|
|
|
—
|
|
|
(5,423)
|
Accretion discount
|
|
|
5,225
|
|
|
5,670
|
Change in production rates, timing, and other
|
|
|
(1,878)
|
|
|
(3,299)
|
Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves
|
|
$
|
38,350
|
|
$
|
52,246
|
|
|
|
|
|
|
|
21. SUBSEQUENT EVENTS
On February 13, 2020, the Board declared that after establishing a cash reserve for the payment of certain amounts outstanding under the Credit Agreement, the Partnership did not have any available cash and, as a result, there would be no cash distribution on the Partnership’s common units. As required by the Amended Partnership Agreement, the Board declared a fourth quarter distribution on the Class C Preferred Units payable 100% in Class C Preferred PIK Units. Accordingly, the Partnership declared an aggregate distribution of 1,039,314 Class C Preferred PIK Units, which was paid on February 28, 2020 to holders of record on February 20, 2020.
On January 13, 2020, we received written notice of termination from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective February 12, 2020.
Since December 31, 2019, the Partnership paid $6.0 million in principal outstanding under the Credit Agreement resulting in total debt outstanding of $144.0 million under the Credit Agreement as of March 13, 2020.
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