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Black Stone Minerals, L.P. Reports Second Quarter Results; Raises Production Guidance for 2019

HOUSTON--(BUSINESS WIRE)--

Black Stone Minerals, L.P. (BSM) ("Black Stone Minerals," "Black Stone," or "the Partnership") today announces its financial and operating results for the second quarter of 2019.

Highlights

  • Reported record production of 52.2 MBoe/d for the second quarter of 2019, led by a 19% quarter-over-quarter increase in royalty production.
  • Reported oil and natural gas revenues of $127.7 million, lease bonus and other income of $6.7 million, and net income of $95.1 million for the quarter.
  • Generated Adjusted EBITDA for the second quarter of $108.3 million.
  • Reported Distributable cash flow of $98.0 million, resulting in distribution coverage for all common units of 1.3x at the previously announced distribution attributable to the second quarter of $0.37 per unit or $1.48 annualized.
  • Raised production guidance for 2019 to range of 47.5 MBoe/d to 50.5 MBoe/d, a 5% increase midpoint to midpoint from prior guidance.
  • Acquired $20.7 million in mineral and royalty assets in the Permian Basin and in East Texas for cash during the second quarter.

Management Commentary

Thomas L. Carter, Jr., Black Stone Minerals’ Chief Executive Officer and Chairman, commented, "Despite a challenging environment for the broader energy sector, Black Stone posted a solid quarter with new records for both total and royalty volumes. We generated distribution coverage of 1.3x while maintaining the $1.48 per unit annualized distribution. Our excess coverage for the quarter funded substantially all of our acquisition and unit repurchase activity during the period. Based on the success of the first six months of the year, we are increasing our production guidance for the year."

Quarterly Financial and Operating Results

Production

Black Stone reported average total production of 52.2 MBoe/d (76% mineral and royalty, 72% natural gas) for the second quarter of 2019. This represents a 17% increase over average total production of 44.7 MBoe/d for the corresponding period in 2018 and an increase of 12% from the first quarter of 2019.

Royalty production was 39.7 MBoe/d (66% natural gas) for the second quarter. This is a sequential increase of 19% from the 33.5 MBoe/d reported in the first quarter of 2019. Royalty production in the corresponding period of 2018 was 31.1 MBoe/d.

Consistent with the Partnership's decision to farm out its working interest participation to third-party capital providers, working interest production continued to decline in the second quarter of 2019 to 12.4 MBoe/d (92% natural gas). This represents declines of 7% and 9%, respectively, from the first quarter of 2019 and the second quarter of 2018.

Realized Prices, Revenues, and Net Income

The Partnership’s average realized price per Boe, excluding the effect of derivative settlements, was $26.90 for the quarter ended June 30, 2019. This represents a 5% decrease from the preceding quarter and reflects lower prices and slightly wider differentials for natural gas and NGLs. Realized prices in the second quarter of 2019 were 17% lower than the $32.22 per Boe reported for the quarter ended June 30, 2018.

Black Stone reported oil and gas revenues of $127.7 million (58% oil and condensate, 42% natural gas and natural gas liquids) for the second quarter of 2019, an increase from $119.3 million in the first quarter of 2019. The increase in oil and gas revenue was driven primarily by higher reported production volumes during the quarter. This increase was partially offset by a lower realized natural gas price for the quarter. Oil and gas revenue in the second quarter of 2018 was $131.1 million.

The Partnership recognized a gain on commodity derivative instruments of $29.2 million in the second quarter of 2019, composed of a $2.9 million realized gain and a $26.3 million unrealized gain that reflects the change in value of the Partnership’s derivative positions during the quarter. Black Stone reported net losses of $41.2 million and $33.3 million on commodity derivative instruments for the quarters ended March 31, 2019 and June 30, 2018, respectively.

Black Stone recognized $6.7 million in lease bonus and other income in the second quarter of 2019, led by leasing activity focused on acreage in the Permian Basin. The Partnership reported $5.6 million and $11.6 million in lease bonus and other income for the first quarter of 2019 and second quarter of 2018, respectively.

The Partnership reported net income of $95.1 million, which includes the non-cash derivative gain described above, for the quarter ended June 30, 2019, compared to net income of $9.0 million in the preceding quarter. Net income for the second quarter of 2018 was $28.7 million.

Adjusted EBITDA and Distributable Cash Flow

Black Stone reported Adjusted EBITDA of $108.3 million for the second quarter of 2019, compared to $94.9 million in the first quarter of 2019 and $100.3 million for the corresponding quarter in 2018. Distributable cash flow for the second quarter of 2019 was $98.0 million, an increase over $81.4 million and $87.2 million in the first quarter of 2019 and second quarter of 2018, respectively.

Financial Position and Activities

As of June 30, 2019, the Partnership had $3.9 million in cash and $436.0 million outstanding under its credit facility.

As of August 2, 2019, the Partnership had $391.0 million outstanding under the credit facility and $6.3 million in cash, providing over $290 million in available liquidity. Black Stone Minerals is in compliance with all financial covenants associated with its credit facility.

During the second quarter of 2019, the Partnership repurchased approximately 137,000 units at an average unit price of $15.90 per unit under the Board-approved $75 million unit repurchase program. This program authorizes Black Stone to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when the Partnership might otherwise be precluded from doing so under applicable laws. Any repurchased units will be canceled.

Hedge Position

Black Stone has commodity derivative contracts in place covering portions of its anticipated production for the remainder of 2019 and 2020. The Partnership's current hedge position is summarized in the following tables:

Oil Hedge Position

 

 

 

 

 

 

Oil Swap

Oil Swap Price

Oil Costless
Collars

Collar Floor

Collar Ceiling

 

MBbl

$/Bbl

MBbl

$/Bbl

$/Bbl

3Q19

855

 

$58.37

 

60

 

$65.00

 

$74.00

4Q19

855

 

$58.37

 

60

 

$65.00

 

$74.00

1Q20

510

 

$57.14

 

210

 

$56.43

 

$67.14

2Q20

510

 

$57.14

 

210

 

$56.43

 

$67.14

3Q20

510

 

$57.14

 

210

 

$56.43

 

$67.14

4Q20

510

 

$57.14

 

210

 

$56.43

 

$67.14

Natural Gas Hedge
Position

 

 

 

Gas Swap

Gas Swap Price

 

MMcf

$/Mcf

3Q19

14,640

$2.96

4Q19

14,640

$2.96

1Q20

8,190

$2.73

2Q20

8,190

$2.73

3Q20

8,280

$2.73

4Q20

8,280

$2.73

More detailed information about the Partnership's existing hedging program can be found in the Quarterly Report on Form 10-Q for the second quarter of 2019, which is expected to be filed on or around August 6, 2019.

Acquisitions

Black Stone acquired $20.7 million of properties in the second quarter of 2019, all of which were purchased with cash. Approximately two-thirds of the acquisitions made during the quarter related to additions in the Permian Basin, with additions in East Texas making up the remainder of the acquisition program for the quarter. Through June 30, 2019, the Partnership has completed $41.6 million in acquisitions in 2019.

Distributions

As previously reported, the Board of Directors of the general partner (the "Board") has approved cash distributions attributable to the second quarter of 2019 of $0.37 per unit for common units. This represents a quarterly distribution coverage ratio of approximately 1.3x. Distributions will be payable on August 22, 2019 to unitholders of record on August 15, 2019.

Activity Update

Well Additions

For the quarter ended June 30, 2019, Black Stone added 382 gross wells (5.25 net). The Partnership is on track to meet or exceed its 2018 additions of approximately 1,465 gross wells and approximately 21 net wells.

Shelby Trough Update

Black Stone expects drilling activity to slow temporarily on its Shelby Trough acreage in East Texas, in part due to the current natural gas price environment. XTO Energy has informed Black Stone that it intends to complete previously drilled wells and, due to constraints in gathering and treating capacity, will pause new drilling activity in the area until the third quarter of 2020. In addition, BPX Energy (“BPX”) recently decided to limit its Shelby Trough drilling activity to a specific area encompassing approximately 17,000 gross acres. Under the terms of the Partnership’s development agreement with BPX, which requires continuous drilling activity to hold acreage, BPX has released over 100,000 gross acres containing an estimated 6 Tcf of potential recoverable resource. Much of this area has been delineated through BPX’s drilling to date with successful wells in both the Haynesville and Bossier shales, and Black Stone intends to place it with another operator or operators. The Partnership estimates this temporary reduction in drilling activity to have a limited impact to its 2019 outlook.

Black Stone recognizes that the natural gas market globally has current challenges that may persist for some time, but believes that growth in U.S. LNG exports, global increases in energy demand and for natural gas demand in particular, and proximity to Gulf Coast markets bode well for its Shelby Trough acreage. “We own this mineral position in perpetuity and have confidence in the long-term potential of this tremendous resource,” said Mr. Carter. “We are very appreciative of the significant de-risking of this asset base done by BPX and look forward to continue working with them on a smaller scale. Our job now is to attract additional capital to our resources here and rationally exploit decades' worth of locations on our Shelby Trough acreage.”

Revised 2019 Guidance

The following table provides the assumptions for Black Stone's original and current 2019 guidance:

 

Original Guidance

 

Revised Guidance

Mineral and royalty production (MBoe/d)

 

35 - 37

 

 

 

36 - 38

 

Working interest production

 

10 - 11

 

 

 

11.5 - 12.5

 

Total production (MBoe/d)

 

45 - 48

 

 

 

47.5 - 50.5

 

Percentage natural gas

 

~71%

 

 

 

~73%

 

Percentage royalty interest

 

~77%

 

 

 

~75%

 

 

 

 

 

 

 

 

 

Lease bonus and other income ($MM)

 

$30 - $40

 

 

 

$20 - $30

 

 

 

 

 

 

 

 

 

Lease operating expense ($MM)

 

$17 - $19

 

 

 

$17 - $19

 

Production costs and ad valorem taxes (as % of total pre-derivative O&G revenue)

 

11% - 13%

 

 

 

11% - 13%

 

Exploration expense ($MM)

 

$1.0 - $2.0

 

 

 

$0.5 - $1.5

 

 

 

 

 

 

 

 

 

G&Acash ($MM)

 

$45 - $47

 

 

 

$44 - $46

 

G&Anon-cash ($MM)

 

$21 - $23

 

 

 

$21 - $23

 

G&Atotal ($MM)

 

$66 - $70

 

 

 

$65 - $69

 

 

 

 

 

 

 

 

 

DD&A ($/Boe)

 

$7.00 - $8.00

 

 

 

$6.50 - $7.50

 

Elimination of Replacement Capital Expenditures

Prior to the conversion of the subordinated units, Black Stone was required under the terms of its partnership agreement to include an estimate of replacement capital expenditures in its calculation of distributable cash flow. With the conversion of the subordinated units being completed in May 2019, the Partnership will no longer make this estimate.

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 2019 on Tuesday, August 6, 2019 at 9:00 a.m. Central Time. To listen to the call by phone, participants should dial (877) 447-4732 and use conference code 5659678; callers are advised to dial into the call 10 minutes in advance of the call start time. 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 5, 2019.

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 in the continental United States. 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. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per unit amounts)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

2019

 

2018

 

2019

 

2018

 

 

 

 

 

 

 

 

 

REVENUE

 

 

 

 

 

 

 

 

Oil and condensate sales

 

$

74,072

 

 

$

77,225

 

 

$

131,776

 

 

$

150,208

 

Natural gas and natural gas liquids sales

 

53,642

 

 

53,854

 

 

115,282

 

 

107,099

 

Lease bonus and other income

 

6,717

 

 

11,577

 

 

12,362

 

 

16,176

 

Revenue from contracts with customers

 

134,431

 

 

142,656

 

 

259,420

 

 

273,483

 

Gain (loss) on commodity derivative instruments

 

29,187

 

 

(33,347

)

 

(11,996

)

 

(49,680

)

TOTAL REVENUE

 

163,618

 

 

109,309

 

 

247,424

 

 

223,803

 

OPERATING (INCOME) EXPENSE

 

 

 

 

 

 

 

 

Lease operating expense

 

3,849

 

 

4,290

 

 

9,141

 

 

8,538

 

Production costs and ad valorem taxes

 

14,450

 

 

14,373

 

 

29,042

 

 

29,298

 

Exploration expense

 

304

 

 

6,745

 

 

308

 

 

6,748

 

Depreciation, depletion, and amortization

 

29,725

 

 

30,292

 

 

57,558

 

 

58,862

 

General and administrative

 

14,347

 

 

19,812

 

 

35,561

 

 

38,333

 

Accretion of asset retirement obligations

 

277

 

 

273

 

 

554

 

 

542

 

(Gain) loss on sale of assets, net

 

 

 

 

 

 

 

(2

)

TOTAL OPERATING EXPENSE

 

62,952

 

 

75,785

 

 

132,164

 

 

142,319

 

INCOME (LOSS) FROM OPERATIONS

 

100,666

 

 

33,524

 

 

115,260

 

 

81,484

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

Interest and investment income

 

47

 

 

37

 

 

93

 

 

70

 

Interest expense

 

(5,652

)

 

(5,280

)

 

(11,177

)

 

(9,801

)

Other income (expense)

 

26

 

 

409

 

 

(72

)

 

(1,106

)

TOTAL OTHER EXPENSE

 

(5,579

)

 

(4,834

)

 

(11,156

)

 

(10,837

)

NET INCOME (LOSS)

 

95,087

 

 

28,690

 

 

104,104

 

 

70,647

 

Net (income) loss attributable to noncontrolling interests

 

 

 

48

 

 

 

 

22

 

Distributions on Series A redeemable preferred units

 

 

 

 

 

 

 

(25

)

Distributions on Series B cumulative convertible preferred units

 

(5,250

)

 

(5,250

)

 

(10,500

)

 

(10,500

)

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS

 

$

89,837

 

 

$

23,488

 

 

$

93,604

 

 

$

60,144

 

ALLOCATION OF NET INCOME (LOSS):

 

 

 

 

 

 

 

 

General partner interest

 

$

 

 

$

 

 

 

 

 

Common units

 

67,718

 

 

17,540

 

 

69,611

 

 

41,877

 

Subordinated units

 

22,119

 

 

5,948

 

 

23,993

 

 

18,267

 

 

 

$

89,837

 

 

$

23,488

 

 

$

93,604

 

 

$

60,144

 

NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:

 

 

 

 

 

 

 

 

Per common unit (basic)

 

$

0.45

 

 

$

0.17

 

 

0.54

 

 

0.40

 

Weighted average common units outstanding (basic)

 

150,101

 

 

105,250

 

 

129,873

 

 

104,516

 

Per subordinated unit (basic)

 

$

0.39

 

 

$

0.06

 

 

0.32

 

 

0.19

 

Weighted average subordinated units outstanding (basic)

 

56,104

 

 

96,329

 

 

76,105

 

 

95,864

 

Per common unit (diluted)

 

$

0.44

 

 

$

0.17

 

 

0.54

 

 

0.40

 

Weighted average common units outstanding (diluted)

 

165,070

 

 

105,250

 

 

129,873

 

 

104,516

 

Per subordinated unit (diluted)

 

$

0.39

 

 

$

0.06

 

 

0.32

 

 

0.19

 

Weighted average subordinated units outstanding (diluted)

 

56,104

 

 

96,329

 

 

76,105

 

 

95,864

 

The following table shows the Partnership’s production, revenues, pricing, and expenses for the periods presented:

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

2019

 

2018

 

2019

 

2018

 

 

 

 

 

 

 

 

 

 

 

(Unaudited)
(Dollars in thousands, except for realized prices and per Boe data)

Production:

 

 

 

 

 

 

 

 

Oil and condensate (MBbls)

 

1,316

 

 

1,183

 

 

2,424

 

 

2,372

 

Natural gas (MMcf)1

 

20,594

 

 

17,311

 

 

39,209

 

 

33,052

 

Equivalents (MBoe)

 

4,748

 

 

4,068

 

 

8,959

 

 

7,881

 

Equivalents/day (MBoe)

 

52.2

 

 

44.7

 

 

49.5

 

 

43.5

 

Revenue:

 

 

 

 

 

 

 

 

Oil and condensate sales

 

$

74,072

 

 

$

77,225

 

 

$

131,776

 

 

$

150,208

 

Natural gas and natural gas liquids sales1

 

53,642

 

 

53,854

 

 

115,282

 

 

107,099

 

Lease bonus and other income

 

6,717

 

 

11,577

 

 

12,362

 

 

16,176

 

Revenue from contracts with customers

 

134,431

 

 

142,656

 

 

259,420

 

 

273,483

 

Gain (loss) on commodity derivative instruments

 

29,187

 

 

(33,347

)

 

(11,996

)

 

(49,680

)

Total revenue

 

$

163,618

 

 

$

109,309

 

 

$

247,424

 

 

$

223,803

 

Realized prices, without derivatives:

 

 

 

 

 

 

 

 

Oil and condensate ($/Bbl)

 

$

56.30

 

 

$

65.28

 

 

$

54.37

 

 

$

63.33

 

Natural gas ($/Mcf)1

 

2.60

 

 

3.11

 

 

2.94

 

 

3.24

 

Equivalents ($/Boe)

 

$

26.90

 

 

$

32.22

 

 

$

27.58

 

 

$

32.65

 

Operating expenses:

 

 

 

 

 

 

 

 

Lease operating expense

 

$

3,849

 

 

$

4,290

 

 

$

9,141

 

 

$

8,538

 

Production costs and ad valorem taxes

 

14,450

 

 

14,373

 

 

29,042

 

 

29,298

 

Exploration expense

 

304

 

 

6,745

 

 

308

 

 

6,748

 

Depreciation, depletion, and amortization

 

29,725

 

 

30,292

 

 

57,558

 

 

58,862

 

General and administrative

 

14,347

 

 

19,812

 

 

35,561

 

 

38,333

 

Per Boe:

 

 

 

 

 

 

 

 

Lease operating expense (per working interest Boe)

 

$

3.40

 

 

$

3.45

 

 

$

3.92

 

 

$

3.42

 

Production costs and ad valorem taxes

 

3.04

 

 

3.53

 

 

3.24

 

 

3.72

 

Depreciation, depletion, and amortization

 

6.26

 

 

7.45

 

 

6.42

 

 

7.47

 

General and administrative

 

3.02

 

 

4.87

 

 

3.97

 

 

4.86

 

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.

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 during the subordination period, 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,

 

 

2019

 

2018

 

2019

 

2018

 

 

 

 

 

 

 

 

 

 

 

(Unaudited)
(In thousands, except per unit amounts)

Net income (loss)

 

$

95,087

 

 

$

28,690

 

 

$

104,104

 

 

$

70,647

 

Adjustments to reconcile to Adjusted EBITDA:

 

 

 

 

 

 

 

 

Depreciation, depletion, and amortization

 

29,725

 

 

30,292

 

 

57,558

 

 

58,862

 

Interest expense

 

5,652

 

 

5,280

 

 

11,177

 

 

9,801

 

Income tax expense (benefit)

 

35

 

 

(446

)

 

166

 

 

1,061

 

Accretion of asset retirement obligations

 

277

 

 

273

 

 

554

 

 

542

 

Equity–based compensation

 

3,816

 

 

9,124

 

 

13,039

 

 

15,350

 

Unrealized (gain) loss on commodity derivative instruments

 

(26,256

)

 

27,057

 

 

16,670

 

 

39,015

 

Adjusted EBITDA

 

108,336

 

 

100,270

 

 

203,268

 

 

195,278

 

Adjustments to reconcile to Distributable cash flow:

 

 

 

 

 

 

 

 

Change in deferred revenue

 

294

 

 

(1

)

 

(10

)

 

1,302

 

Cash interest expense

 

(5,392

)

 

(4,969

)

 

(10,661

)

 

(9,285

)

(Gain) loss on sale of assets, net

 

 

 

 

 

 

 

(2

)

Estimated replacement capital expenditures1

 

 

 

(2,750

)

 

(2,750

)

 

(6,000

)

Cash paid to noncontrolling interests

 

 

 

(62

)

 

 

 

(114

)

Preferred unit distributions

 

(5,250

)

 

(5,250

)

 

(10,500

)

 

(10,525

)

Distributable cash flow

 

$

97,988

 

 

$

87,238

 

 

$

179,347

 

 

$

170,654

 

 

 

 

 

 

 

 

 

 

Total units outstanding2

 

205,962

 

 

203,148

 

 

 

 

 

Distributable cash flow per unit

 

$

0.476

 

 

$

0.429

 

 

 

 

 

Common unit price as of August 2, 2019 and August 3, 2018, respectively

 

$

14.97

 

 

$

17.17

 

 

 

 

 

Implied Distributable cash flow yield

 

12.7

%

 

10.0

%

 

 

 

 

1

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. On April 27, 2018, the Board approved a replacement capital expenditure estimate of $11.0 million for the period of April 1, 2018 to March 31, 2019. No replacement capital expenditure estimate will be established for periods subsequent to March 31, 2019.

2

The distribution attributable to the three months ended June 30, 2019 is estimated using 205,961,594 common units as of July 30, 2019; the exact amount of the distribution attributable to the three months ended June 30, 2019 will be determined based on units outstanding as of the record date of August 15, 2019. Distributions attributable to the three months ended June 30, 2018 were calculated using 106,819,353 common units and 96,328,836 subordinated units as of the record date of August 16, 2018.

 

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