 | Exhibit 99.1 News For Immediate Release |
Black Stone Minerals, L.P. Reports Record Quarterly Results And
Declares Increased Cash Distribution on Common and Subordinated Units;
Raises Production Guidance for Full Year 2018
HOUSTON, August 6, 2018 (BUSINESS WIRE) - Black Stone Minerals, L.P. (NYSE: BSM) ("Black Stone Minerals," "Black Stone," or "the Partnership") today announces its financial and operating results for the second quarter of 2018 and recent developments after quarter-end.
Highlights
• | Reported total quarterly production of 44.7 Mboe/d, an increase of 5% over the first quarter of 2018. Royalty volumes increased by 9% over first quarter while working interest volumes declined by 2%. |
• | Reported oil and gas revenues of $131.1 million and lease bonus and other income of $11.6 million for the quarter. |
• | Generated net income of $28.7 million and Adjusted EBITDA of $100.3 million. |
• | Announced an 8% increase in distributions per common unit for the second quarter. |
• | Reported distributable cash flow of $87.2 million, resulting in distribution coverage for all units of 1.3x on increased distribution level. |
• | Production guidance for 2018 increased to a range of 44.5 to 45.5 MBoe/d, a 7% increase midpoint to midpoint from prior guidance. |
• | Acquired $26.5 million in mineral and royalty assets for cash during the second quarter in Permian Basin and East Texas, and closed on an approximately $17 million of additional mineral and royalty assets subsequent to quarter end. |
Management Commentary
Thomas L. Carter, Jr., Black Stone Minerals’ Chief Executive Officer and Chairman, commented, "The second quarter was another strong quarter for Black Stone Minerals and we are performing well on a number of fronts. We are raising our production guidance for the full year to a midpoint of 45 MBoe/d, which implies continued production growth in the back half of the year off a very strong first six months. We're seeing a lot of activity on our acreage in the first half of 2018, which puts us on pace to handily beat the number of wells we added in 2017. I'd also add that our undeveloped acreage continues to attract interest from industry as demonstrated by the nearly $12 million in lease bonus we collected in the quarter. Based on our strong operational and financial performance, we are increasing the distribution for both common and subordinated units to an annualized rate of $1.35 per unit while retaining a healthy amount of cash flow to support the growth of the business. Based on our closing price as of Friday, that equates to a current distribution yield of 7.9%, and our distributable cash flow yield is 10.0% which is well in excess of that of our direct peers. I think Black Stone represents a tremendous opportunity for long-term investors who want exposure to diverse, actively managed mineral and royalty assets."
Quarterly Financial and Operating Results
Production
Black Stone reported average production of 44.7 MBoe/d (69% mineral and royalty, 71% natural gas) for the second quarter of 2018. This represents an increase of 20% over average production of 37.3 MBoe/d for the corresponding period in 2017 and is 5% higher than average daily production in the first quarter of 2018. Oil production for the period was essentially flat with record levels reported in the first quarter of 2018. Natural gas production increased by 9% from the first quarter of 2018 due in large part to a significant number of East Texas Haynesville/Bossier wells being turned to sales in the second quarter, including the last wells not covered by the Partnership's farmout arrangements in the Shelby Trough.
Realized Prices, Revenues, and Net Income
The Partnership’s average realized price per Boe, excluding the effect of derivative settlements, was $32.22 for the quarter ended June 30, 2018. This represents a 3% decrease from the preceding quarter and is 26% higher than the $25.67 per Boe reported for the quarter ended June 30, 2017.
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Black Stone reported oil and gas revenues of $131.1 million (59% oil and condensate) for the second quarter of 2018, an increase of 50% from $87.2 million for the second quarter of 2017. This increase in oil and gas revenue was driven by the aforementioned increases in reported production volumes and realized pricing. Oil and gas revenue in the first quarter of 2018 was $126.2 million.
The Partnership recognized a loss on commodity derivative instruments of $33.3 million in the second quarter of 2018, composed of a $6.3 million loss from realized settlements during the quarter and a $27.1 million unrealized loss that reflects the change in value of the Partnership’s derivative positions during the quarter. In the second quarter of 2017, the Partnership reported a gain on commodity derivative instruments of $22.0 million which reflected a significant unrealized gain in the quarter.
Black Stone recognized $11.6 million in lease bonus and other income in the second quarter of 2018, led by leasing activity in the Midland and Delaware basins in West Texas with additional leases written in the Bakken/Three Forks in North Dakota, the Austin Chalk in East Texas, and the Louisiana portion of the Haynesville/Bossier trend. The Partnership reported $11.4 million in lease bonus and other income in the same period in 2017.
The Partnership reported net income of $28.7 million, which includes the non-cash derivative loss described above, for the quarter ended June 30, 2018, compared to net income of $54.2 million in the corresponding period in 2017.
Adjusted EBITDA and Distributable Cash Flow
Black Stone reported new quarterly records as a public company for both Adjusted EBITDA and distributable cash flow in the second quarter of 2018. Adjusted EBITDA was $100.3 million for the second quarter of 2018, compared to $74.7 million for the corresponding quarter in 2017 and $95.0 million in the first quarter of 2018. Distributable cash flow for the second quarter of 2018 was $87.2 million, an increase of 32% from the $66.3 million reported in the second quarter of 2017 and a 5% increase from the $83.4 million in the first quarter of 2018. The Partnership expects to distribute approximately $68 million to unitholders with respect to the second quarter with the balance invested in the continued growth of the business.
Financial Position
As of June 30, 2018, the Partnership had $7.1 million in cash and $421.0 million outstanding under its credit facility. As of August 3, 2018 and taking into account the acquisitions closed subsequent to the end of the second quarter, the Partnership had $395.0 million outstanding under the credit facility and $18.9 million in cash, providing $223.9 million in available liquidity. Black Stone Minerals is in compliance with all financial covenants associated with its credit facility.
Hedge Position
Black Stone has commodity derivative contracts in place covering portions of its anticipated production for the remainder of 2018 as well as 2019 and 2020. For the balance of 2018, approximately 72% of expected oil volumes are hedged at prices averaging $55.23 per barrel and approximately 73% of expected gas volumes are hedged at prices averaging $3.01 per Mcf through the use of swaps. For 2019, the Partnership has used swaps to hedge 645 MBbl of oil per quarter at prices averaging $58.43 per barrel and an average of 7,250 MMcf of natural gas per quarter at an average price of $2.86 per Mcf. For 2020, Black Stone has entered into costless collars covering 150 MBbl per quarter at a range of $55.00 to $65.75 per barrel. More detailed information about the Partnership's existing hedge position can be found in the Quarterly Report on Form 10-Q for the second quarter of 2018, which is expected to be filed on or around August 7, 2018.
Acquisitions
Black Stone acquired $26.5 million of properties for cash in the second quarter of 2018. Included in that amount was a $14.6 million mineral package with assets located in the Midland and Delaware basins. Additionally, the Partnership spent $11.9 million in cash to further consolidate its acreage position in the Shelby Trough area in East Texas.
Subsequent to quarter end, Black Stone closed on the acquisition of approximately $17 million of additional mineral and royalty assets, which included $10.8 million of assets which share common underlying properties as those acquired in the Noble Acquisition that was completed in late 2017. Year to date, the Partnership has acquired over $75 million of mineral and royalty properties.
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Development Capital Expenditures
The Partnership invested a net total of $4.4 million in development capital (working interest participation and drilling activities) during the second quarter of 2018, inclusive of $23.0 million in reimbursements from farmout partners. As a result of the previously announced farmouts with Canaan Resource Partners and Pivotal Petroleum Partners, substantially all capital expenditures made by Black Stone to drill and complete Haynesville/Bossier wells in the Shelby Trough area of East Texas are reimbursed by those partners. The vast majority of net development capital for the quarter relates to activity related to the delineation of the PepperJack prospect in Hardin and Liberty counties, Texas.
Through the first six months of 2018, the Partnership invested a total of $32.6 million in net development capital expenditures. Black Stone spent $20.7 million in the first half of 2018 on working interest participation capital related primarily to Haynesville/Bossier development in the Shelby Trough, net of farmout reimbursements. Black Stone also spent $11.9 million in the first half of 2018 delineating its PepperJack prospect targeting the Lower Wilcox formation. The PepperJack A#1 well was drilled and logged during the fourth quarter of 2017 and the first quarter of 2018. The Partnership believes the well is highly prospective and will be completed as a commercially productive well. The PepperJack B#1 well was a significant step-out from the PepperJack A#1 well, and was drilled and logged during the second quarter of 2018. Black Stone does not believe this well will be completed in the near term and accordingly recognized $6.7 million of exploration expense in the second quarter of 2018 for the costs associated with the PepperJack B#1. The Partnership is in active negotiations with industry operating partners for third-party development of the PepperJack prospect.
Given the current farmout agreements in place, the Partnership expects negligible development capital expenditures related to working interest participation for the remainder of 2018.
Distributions
The Board of Directors of the general partner (the "Board") has approved cash distributions attributable to the second quarter of 2018 of $0.3375 per unit for both common and subordinated units. This represents an approximate 8% increase to the distribution for common unitholders from the previous quarter. The quarterly distribution coverage ratio attributable to the second quarter of 2018 was approximately 1.3x for all units. Distributions will be payable on August 23, 2018 to unitholders of record on August 16, 2018.
Revised 2018 Guidance
The following table provides the assumptions for Black Stone's original and current 2018 guidance:
Original Guidance | Revised Guidance | ||||||
Average daily production (MBoe/d) | 41 - 43 | 44.5 - 45.5 | |||||
Percentage natural gas | ~75% | ~71% | |||||
Percentage royalty interest | ~65% | ~68% | |||||
Lease bonus and other income ($MM) | $30 - $40 | $30 - $40 | |||||
Lease operating expense ($MM) | $15 - $19 | $16 - $18 | |||||
Production costs and ad valorem taxes (as % of total pre-derivative O&G revenue) | 12% - 14% | 11% - 13% | |||||
Exploration expense ($MM) | $1.5 - $2.5 | $7.5 - $8.5 | |||||
G&A — cash ($MM) | $45 - $47 | $45 - $47 | |||||
G&A — non-cash ($MM) | $28 - $30 | $30 - $32 | |||||
G&A — total ($MM) | $73 - $77 | $75 - $79 | |||||
DD&A ($/Boe) | $8.00 - $9.00 | $7.00 - $8.00 | |||||
Conference Call
Black Stone Minerals will host a conference call and webcast for investors and analysts to discuss its results for the second quarter of 2018 on Tuesday, August 7, 2018 at 9:00 a.m. Central Time. To join the call, participants should dial (877) 447-4732 and use conference code 3916319. A live broadcast of the call will also be available at http://investor.blackstoneminerals.com. A recording of the conference call will be available at that site through September 7, 2018.
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About Black Stone Minerals, L.P.
Black Stone Minerals is one of the largest owners of oil and natural gas mineral interests in the United States. The Partnership owns mineral interests and royalty interests in 41 states and 64 onshore basins in the continental United States. The Partnership also owns and selectively participates as a non-operating working interest partner in established development programs, primarily on its mineral and royalty holdings. The Partnership expects that its large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests will result in production and reserve growth, as well as increasing quarterly distributions to its unitholders.
Forward-Looking Statements
This news release includes forward-looking statements. All statements, other than statements of historical facts, included in this news release that address activities, events, or developments that the Partnership expects, believes, or anticipates will or may occur in the future are forward-looking statements. Terminology such as "will," "may," "should," "expect," "anticipate," "plan," "project," "intend," "estimate," "believe," "target," "continue," "potential," the negative of such terms, or other comparable terminology often identify forward-looking statements. Except as required by law, Black Stone Minerals undertakes no obligation, and does not intend, to update these forward-looking statements to reflect events or circumstances occurring after this news release. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this news release. All forward-looking statements are qualified in their entirety by these cautionary statements. These forward-looking statements involve risks and uncertainties, many of which are beyond the control of Black Stone Minerals, which may cause the Partnership’s actual results to differ materially from those implied or expressed by the forward-looking statements.
Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
• | the Partnership’s ability to execute its business strategies; |
• | the volatility of realized oil and natural gas prices; |
• | the level of production on the Partnership’s properties; |
• | regional supply and demand factors, delays, or interruptions of production; |
• | the Partnership’s ability to replace its oil and natural gas reserves; and |
• | the Partnership’s ability to identify, complete, and integrate acquisitions. |
For an important discussion of risks and uncertainties that may impact our operations, see our annual and quarterly filings with the Securities and Exchange Commission, which are available on our website.
Information for Non-U.S. Investors
This press release is intended to be a qualified notice under Treasury Regulation Section 1.1446-4(b). Although a portion of Black Stone Minerals’ income may not be effectively connected income and may be subject to alternative withholding procedures, brokers and nominees should treat 100% of Black Stone Minerals’ distributions to non-U.S. investors as being attributable to income that is effectively connected with a United States trade or business. Accordingly, Black Stone Minerals’ distributions to non-U.S. investors are subject to federal income tax withholding at the highest marginal rate, currently 37.0% for individuals.
Black Stone Minerals, L.P. Contact
Brent Collins
Vice President, Investor Relations
Telephone: (713) 445-3200
investorrelations@blackstoneminerals.com
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BLACK STONE MINERALS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per unit amounts)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
REVENUE | ||||||||||||||||
Oil and condensate sales | $ | 77,225 | $ | 37,262 | $ | 150,208 | $ | 77,736 | ||||||||
Natural gas and natural gas liquids sales | 53,854 | 49,903 | 107,099 | 97,604 | ||||||||||||
Lease bonus and other income | 11,577 | 11,356 | 16,176 | 25,038 | ||||||||||||
Revenue from contracts with customers | 142,656 | 98,521 | 273,483 | 200,378 | ||||||||||||
Gain (loss) on commodity derivative instruments | (33,347 | ) | 22,003 | (49,680 | ) | 44,728 | ||||||||||
TOTAL REVENUE | 109,309 | 120,524 | 223,803 | 245,106 | ||||||||||||
OPERATING (INCOME) EXPENSE | ||||||||||||||||
Lease operating expense | 4,290 | 4,148 | 8,538 | 8,337 | ||||||||||||
Production costs and ad valorem taxes | 14,373 | 11,863 | 29,298 | 23,765 | ||||||||||||
Exploration expense | 6,745 | 46 | 6,748 | 608 | ||||||||||||
Depreciation, depletion, and amortization | 30,292 | 28,900 | 58,862 | 55,279 | ||||||||||||
General and administrative | 19,812 | 17,481 | 38,333 | 34,693 | ||||||||||||
Accretion of asset retirement obligations | 273 | 253 | 542 | 500 | ||||||||||||
(Gain) loss on sale of assets, net | — | (7 | ) | (2 | ) | (931 | ) | |||||||||
TOTAL OPERATING EXPENSE | 75,785 | 62,684 | 142,319 | 122,251 | ||||||||||||
INCOME (LOSS) FROM OPERATIONS | 33,524 | 57,840 | 81,484 | 122,855 | ||||||||||||
OTHER INCOME (EXPENSE) | ||||||||||||||||
Interest and investment income | 37 | 33 | 70 | 39 | ||||||||||||
Interest expense | (5,280 | ) | (3,981 | ) | (9,801 | ) | (7,488 | ) | ||||||||
Other income (expense) | 409 | 282 | (1,106 | ) | 351 | |||||||||||
TOTAL OTHER EXPENSE | (4,834 | ) | (3,666 | ) | (10,837 | ) | (7,098 | ) | ||||||||
NET INCOME (LOSS) | 28,690 | 54,174 | 70,647 | 115,757 | ||||||||||||
Net (income) loss attributable to noncontrolling interests | 48 | 16 | 22 | 7 | ||||||||||||
Distributions on Series A redeemable preferred units | — | (672 | ) | (25 | ) | (1,786 | ) | |||||||||
Distributions on Series B cumulative convertible preferred units | (5,250 | ) | — | (10,500 | ) | — | ||||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS | $ | 23,488 | $ | 53,518 | $ | 60,144 | $ | 113,978 | ||||||||
ALLOCATION OF NET INCOME (LOSS): | ||||||||||||||||
General partner interest | $ | — | $ | — | $ | — | $ | — | ||||||||
Common units | 17,540 | 32,100 | 41,884 | 67,617 | ||||||||||||
Subordinated units | 5,948 | 21,418 | 18,260 | 46,361 | ||||||||||||
$ | 23,488 | $ | 53,518 | $ | 60,144 | $ | 113,978 | |||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||||||||||||||
Per common unit (basic) | $ | 0.17 | $ | 0.33 | $ | 0.40 | $ | 0.69 | ||||||||
Weighted average common units outstanding (basic) | 105,250 | 97,990 | 103,937 | 97,448 | ||||||||||||
Per subordinated unit (basic) | $ | 0.06 | $ | 0.22 | $ | 0.19 | $ | 0.49 | ||||||||
Weighted average subordinated units outstanding (basic) | 96,329 | 95,388 | 95,395 | 95,269 | ||||||||||||
Per common unit (diluted) | $ | 0.17 | $ | 0.33 | $ | 0.40 | $ | 0.69 | ||||||||
Weighted average common units outstanding (diluted) | 105,250 | 97,990 | 103,937 | 97,448 | ||||||||||||
Per subordinated unit (diluted) | $ | 0.06 | $ | 0.22 | $ | 0.19 | $ | 0.49 | ||||||||
Weighted average subordinated units outstanding (diluted) | 96,329 | 95,388 | 95,395 | 95,269 | ||||||||||||
DISTRIBUTIONS DECLARED AND PAID: | ||||||||||||||||
Per common unit | $ | 0.3125 | $ | 0.2875 | $ | 0.6250 | $ | 0.5750 | ||||||||
Per subordinated unit | $ | 0.2087 | $ | 0.1838 | $ | 0.4175 | $ | 0.3675 | ||||||||
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The following table shows the Partnership’s production, revenues, realized prices, and expenses for the periods presented.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
(Unaudited) (Dollars in thousands, except for realized prices and per Boe data) | ||||||||||||||||
Production: | ||||||||||||||||
Oil and condensate (MBbls) | 1,183 | 824 | 2,372 | 1,685 | ||||||||||||
Natural gas (MMcf)1 | 17,311 | 15,425 | 33,052 | 29,485 | ||||||||||||
Equivalents (MBoe) | 4,068 | 3,395 | 7,881 | 6,599 | ||||||||||||
Equivalents/day (MBoe) | 44.7 | 37.3 | 43.5 | 36.5 | ||||||||||||
Revenue: | ||||||||||||||||
Oil and condensate sales | $ | 77,225 | $ | 37,262 | $ | 150,208 | $ | 77,736 | ||||||||
Natural gas and natural gas liquids sales1 | 53,854 | 49,903 | 107,099 | 97,604 | ||||||||||||
Lease bonus and other income | 11,577 | 11,356 | 16,176 | 25,038 | ||||||||||||
Revenue from contracts with customers | 142,656 | 98,521 | 273,483 | 200,378 | ||||||||||||
Gain (loss) on commodity derivative instruments | (33,347 | ) | 22,003 | (49,680 | ) | 44,728 | ||||||||||
Total revenue | $ | 109,309 | $ | 120,524 | $ | 223,803 | $ | 245,106 | ||||||||
Realized prices: | ||||||||||||||||
Oil and condensate ($/Bbl) | $ | 65.28 | $ | 45.22 | $ | 63.33 | $ | 46.13 | ||||||||
Natural gas ($/Mcf)1 | 3.11 | 3.24 | 3.24 | 3.31 | ||||||||||||
Equivalents ($/Boe) | $ | 32.22 | $ | 25.67 | $ | 32.65 | $ | 26.57 | ||||||||
Operating expenses: | ||||||||||||||||
Lease operating expense | $ | 4,290 | $ | 4,148 | $ | 8,538 | $ | 8,337 | ||||||||
Production costs and ad valorem taxes | 14,373 | 11,863 | 29,298 | 23,765 | ||||||||||||
Exploration expense | 6,745 | 46 | 6,748 | 608 | ||||||||||||
Depreciation, depletion, and amortization | 30,292 | 28,900 | 58,862 | 55,279 | ||||||||||||
General and administrative | 19,812 | 17,481 | 38,333 | 34,693 | ||||||||||||
Per Boe: | ||||||||||||||||
Lease operating expense (per working interest Boe) | $ | 3.45 | $ | 2.83 | $ | 3.42 | $ | 3.00 | ||||||||
Production costs and ad valorem taxes | 3.53 | 3.49 | 3.72 | 3.60 | ||||||||||||
Depreciation, depletion, and amortization | 7.45 | 8.51 | 7.47 | 8.38 | ||||||||||||
General and administrative | 4.87 | 5.15 | 4.86 | 5.26 | ||||||||||||
1 | As a mineral-and-royalty-interest owner, Black Stone Minerals is often provided insufficient and inconsistent data on natural gas liquid ("NGL") volumes by its operators. As a result, the Partnership is unable to reliably determine the total volumes of NGLs associated with the production of natural gas on its acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in natural gas revenue and the calculation of realized prices for natural gas. |
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Non-GAAP Financial Measures
Adjusted EBITDA and distributable cash flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.
We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, and non-cash equity-based compensation. We define distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, estimated replacement capital expenditures, cash interest expense, and distributions to noncontrolling interests and preferred unitholders.
Adjusted EBITDA and distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles (“GAAP”) in the United States as measures of our financial performance.
Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and distributable cash flow may differ from computations of similarly titled measures of other companies.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
(Unaudited) (In thousands, except per unit amounts) | ||||||||||||||||
Net income | $ | 28,690 | $ | 54,174 | $ | 70,647 | $ | 115,757 | ||||||||
Adjustments to reconcile to Adjusted EBITDA: | ||||||||||||||||
Depreciation, depletion, and amortization | 30,292 | 28,900 | 58,862 | 55,279 | ||||||||||||
Interest expense | 5,280 | 3,981 | 9,801 | 7,488 | ||||||||||||
Income tax expense | (446 | ) | — | 1,061 | — | |||||||||||
Accretion of asset retirement obligations | 273 | 253 | 542 | 500 | ||||||||||||
Equity–based compensation | 9,124 | 6,278 | 15,350 | 10,939 | ||||||||||||
Unrealized (gain) loss on commodity derivative instruments | 27,057 | (18,921 | ) | 39,015 | (37,368 | ) | ||||||||||
Adjusted EBITDA | 100,270 | 74,665 | 195,278 | 152,595 | ||||||||||||
Adjustments to reconcile to distributable cash flow: | ||||||||||||||||
Deferred revenue | (1 | ) | (643 | ) | 1,302 | (969 | ) | |||||||||
Cash interest expense | (4,969 | ) | (3,760 | ) | (9,285 | ) | (7,053 | ) | ||||||||
(Gain) loss on sale of assets, net | — | (7 | ) | (2 | ) | (931 | ) | |||||||||
Estimated replacement capital expenditures1 | (2,750 | ) | (3,250 | ) | (6,000 | ) | (7,000 | ) | ||||||||
Cash paid to noncontrolling interests | (62 | ) | (41 | ) | (114 | ) | (66 | ) | ||||||||
Preferred unit distributions | (5,250 | ) | (672 | ) | (10,525 | ) | (1,786 | ) | ||||||||
Distributable cash flow | $ | 87,238 | $ | 66,292 | $ | 170,654 | $ | 134,790 | ||||||||
Total units outstanding2 | 202,364 | 196,648 | ||||||||||||||
Distributable cash flow per unit | $ | 0.431 | $ | 0.337 | ||||||||||||
Common unit price as of August 3, 2018 | $ | 17.17 | ||||||||||||||
Implied distributable cash flow yield | 10.0 | % | ||||||||||||||
1 | On August 3, 2016, the Board approved a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017. On June 8, 2017, the Board approved a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018. |
2 | The distribution attributable to the three months ended June 30, 2018 is estimated using 106,035 common units and 96,329 subordinated units as of August 1, 2018; the exact amount of the distribution attributable to the three months ended June 30, 2018 will be determined based on units outstanding as of the record date of August 16, 2018. Distributions attributable to the three months ended June 30, 2017 were calculated using 101,260 common units and 95,388 subordinated units as of the record date of August 17, 2017. |
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