Holly Energy Partners, L.P. Reports Third Quarter Results

Oct 28, 2010, 07:00 ET from Holly Energy Partners, L.P.

DALLAS, Oct. 28 /PRNewswire-FirstCall/ -- Holly Energy Partners, L.P. ("HEP" or the "Partnership") (NYSE: HEP) today reported financial results for the third quarter of 2010.  For the quarter, distributable cash flow was $24 million, up $3.3 million, or 16% compared to third quarter of 2009.  For the nine months ended September 30, 2010, distributable cash flow was $66.8 million, up $15.1 million or 29% compared to the same period of 2009.  Based on these results, HEP announced a distribution increase on October 26, 2010, raising the quarterly distribution from $0.825 to $0.835 per unit, representing a 5% increase over the distribution for the third quarter of 2009.

For the quarter, income from continuing operations was $16.3 million ($0.59 per basic and diluted limited partner unit) compared to $15.5 million ($0.73 per basic and diluted limited partner unit) for the third quarter of 2009.  Net income was $16.3 million ($0.59 per basic and diluted limited partner unit) versus $16.5 million ($0.78 per basic and diluted limited partner unit) for the third quarter of 2009, which included Rio Grande discontinued operations.  Excluding discontinued operations, the slight increase in overall earnings is due principally to contributions from our December 2009 and March 2010 asset acquisitions, partially offset by a decrease in realized deferred revenue, lower shipment volumes and increased interest costs.

For the current nine month period, income from continuing operations was $40.4 million ($1.43 per basic and diluted limited partner unit) compared to $34.3 million ($1.66 per basic and diluted limited partner unit) for the same nine month period of 2009.  Net income was $40.4 million ($1.43 per basic and diluted limited partner unit) versus $38.4 million ($1.89 per basic and diluted limited partner unit) for the first nine months of 2009.

Commenting on the third quarter of 2010, Matt Clifton, Chairman of the Board and Chief Executive Officer stated, "The third quarter generated solid financial results as distributable cash flow and EBITDA again reached new quarterly highs.  For the quarter, increased distributable cash flow over the same period of 2009 allowed us to declare our 24th consecutive distribution increase.  EBITDA was $32 million, an increase of $2.1 million or 7% over last year's third quarter, and for the current nine month period, EBITDA was $88.2 million, an increase of $13.3 million or 18% over last year's respective period, reflecting earnings contributions from our 2009 and March 2010 asset acquisitions.  Although shipments on our pipelines did not meet targeted levels, we are pleased with these operating results."

"Looking forward, we will continue to explore opportunities that should provide further growth in our distributable cash flow, asset base and geographic footprint," Clifton said.

Third Quarter 2010 Revenue Highlights

Total revenues from continuing operations for the quarter were $46.5 million, a $5.7 million increase compared to the third quarter of 2009.  This was due to revenues attributable to our December 2009 and March 2010 asset acquisitions, partially offset by a $3.4 million decrease in previously deferred revenue realized and a decrease in pipeline shipments.  The small decrease in affiliate pipeline shipments reflects slightly lower run rates at Holly's Navajo refinery during the third quarter due to the impact of unscheduled downtime of certain operating units.

  • Revenues from our refined product pipelines were $19.6 million, a decrease of $3.2 million.  This decrease is primarily due to a $3.2 million decrease in previously deferred revenue realized.   Volumes shipped on our refined product pipelines averaged 135.2 thousand barrels per day ("mbpd") compared to 142.8 mbpd for the third quarter of 2009.
  • Revenues from our intermediate pipelines were $4.9 million, a decrease of $0.5 million, on shipments averaging 83.2 mbpd compared to 88.1 mbpd for the third quarter of 2009.  This includes a $0.2 million decrease in previously deferred revenue realized.
  • Revenues from our crude pipelines were $9.8 million, an increase of $2.2 million.  This increase is primarily due to $2.3 million in revenues attributable to our Roadrunner Pipeline agreement entered into in December 2009.  Volumes shipped on our crude pipelines averaged 143.6 mbpd compared to 143.9 mbpd for the third quarter of 2009.
  • Revenues from terminal, tankage and loading rack fees were $12.2 million, an increase of $7.2 million compared to the third quarter of 2009.  This increase includes $7.1 million in revenues attributable to volumes transferred and stored at our Tulsa storage and rack facilities.

Revenues from continuing operations for the three months ended September 30, 2010 include the recognition of $1.6 million of prior shortfalls billed to shippers in 2009, as they did not meet their minimum volume commitments in any of the subsequent four quarters.  As of September 30, 2010, deferred revenue in our consolidated balance sheet was $11.7 million.  Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels or when shipping rights expire unused over the next four quarters.

Nine Months Ended September 30, 2010 Revenue Highlights

Total revenues from continuing operations for the nine months were $132.7 million, a $24.6 million increase compared to the same period of 2009.  This was due to our recent asset acquisitions and higher tariffs on affiliate shipments, partially offset by an $8.1 million decrease in previously deferred revenue realized.  On a year-to-date basis, overall pipeline shipments were up 7%, reflecting increased affiliate volumes attributable to Holly Corporation's ("Holly") first quarter of 2009 Navajo refinery expansion, including volumes shipped on our new 16" intermediate and Beeson pipelines, partially offset by a decrease in third-party shipments.  Additionally, prior year affiliate shipments reflect lower first quarter volumes as a result of production downtime during a major maintenance turnaround of the Navajo refinery during the first quarter of 2009.  

  • Revenues from our refined product pipelines were $55 million, a decrease of $7.3 million.  This decrease is primarily due to a $9.1 million decrease in previously deferred revenue realized. Volumes shipped on our refined product pipelines averaged 130.9 mbpd compared to 131.1 mbpd for the first nine months of 2009, reflecting a decline in third-party shipments, offset by an increase in affiliate shipments.
  • Revenues from our intermediate pipelines were $15.7 million, an increase of $4.2 million, on shipments averaging 82.8 mbpd compared to 64.5 mbpd for the nine months ended September 30, 2009.  This increase is primarily due to volumes shipped on our 16-inch intermediate pipeline combined with a $1 million increase in previously deferred revenue realized.
  • Revenues from our crude pipelines were $28.9 million, an increase of $7.7 million, on shipments averaging 140 mbpd compared to 136.3 mbpd for the nine months ended September 30, 2009.  This increase is primarily due to $6.9 million in revenues attributable to our Roadrunner Pipeline agreement.
  • Revenues from terminal, tankage and loading rack fees were $33.1 million, an increase of $20 million compared to the nine months ended September 30, 2009.  This increase includes $19 million in revenues attributable to volumes transferred and stored at our Tulsa storage and rack facilities.

Our revenues from continuing operations for the nine months ended September 30, 2010 include the recognition of $5.7 million of prior shortfalls billed to shippers in 2009, as they did not meet their minimum volume commitments in any of the subsequent four quarters.

Cost and Expense Highlights

Operating costs and expenses were $22.4 million and $68.2 million for the three and nine months ended September 30, 2010, respectively, representing increases of $2.8 million and $11.9 million compared to the same periods of 2009.  These increases were due to costs attributable to our recent asset acquisitions, higher year-to-date throughput volumes on our heritage pipelines, early 2010 transaction related expenses, and higher depreciation, maintenance and payroll expense.

Additionally, interest expense was $8.4 million and $25.5 million for the three and nine months ended September 30, 2010, respectively, representing increases of $2 million and $9.3 million compared to the same periods of 2009.   These increases reflect interest on our 8.25% senior notes issued in March 2010 and costs of $1.1 million from a partial settlement of an interest rate swap in the second quarter of 2010.

We have scheduled a webcast conference call today at 4:00 PM Eastern Time to discuss financial results. This webcast may be accessed at: http://www.videonewswire.com/event.asp?id=73286.

An audio archive of this webcast will be available using the above noted link through November 11, 2010.  

About Holly Energy Partners, L.P.

Holly Energy Partners, L.P., headquartered in Dallas, Texas, provides petroleum product and crude oil transportation, terminalling, storage and throughput services to the petroleum industry, including Holly Corporation subsidiaries. The Partnership owns and operates petroleum product and crude gathering pipelines, tankage and terminals in Texas, New Mexico, Arizona, Washington, Idaho, Oklahoma and Utah.  In addition, the Partnership owns a 25% interest in SLC Pipeline LLC, a 95-mile intrastate pipeline system serving refineries in the Salt Lake City, Utah area.

Holly Corporation operates through its subsidiaries a 100,000 barrels-per-stream-day ("bpsd") refinery located in Artesia, New Mexico, a 31,000 bpsd refinery in Woods Cross, Utah and a 125,000 bpsd refinery in Tulsa, Oklahoma.  A Holly Corporation subsidiary owns a 34% interest (including the general partner interest) in the Partnership.

The following is a "safe harbor" statement under the Private Securities Litigation Reform Act of 1995: The statements in this press release relating to matters that are not historical facts are "forward-looking statements" within the meaning of the federal securities laws.  Forward looking statements use words such as "anticipate," "project," "expect," "plan," "goal," "forecast," "intend," "could," "believe," "may," and similar expressions and statements regarding our plans and objectives for future operations.  These statements are based on our beliefs and assumptions and those of our general partner using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties.  Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurance that our expectations will prove to be correct.  Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

  • risks and uncertainties with respect to the actual quantities of petroleum products and crude oil shipped on our pipelines and/or terminalled in our terminals;
  • the economic viability of Holly Corporation, Alon USA, Inc. and our other customers;
  • the demand for refined petroleum products in markets we serve;
  • our ability to successfully purchase and integrate additional operations in the future;
  • our ability to complete previously announced or contemplated acquisitions;
  • the availability and cost of additional debt and equity financing;
  • the possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;
  • the effects of current and future government regulations and policies;
  • our operational efficiency in carrying out routine operations and capital construction projects;
  • the possibility of terrorist attacks and the consequences of any such attacks;
  • general economic conditions; and
  • other financial, operations and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes  

The following tables present income, distributable cash flow and volume information for the three and the nine months ended September 30, 2010 and 2009.  

Three Months Ended

September 30,

Change from

2010

2009

2009

(In thousands, except per unit data)

Revenues

Pipelines:

  Affiliates – refined product pipelines

$    12,340

$  12,267

$    73

  Affiliates – intermediate pipelines

4,917

5,370

(453)

  Affiliates – crude pipelines

9,774

7,563

2,211

27,031

25,200

1,831

  Third parties – refined product pipelines

7,277

10,552

(3,275)

34,308

35,752

(1,444)

Terminals and loading racks:

  Affiliates

10,282

3,159

7,123

  Third parties

1,959

1,894

65

12,241

5,053

7,188

Total revenues

46,549

40,805

5,744

Operating costs and expenses:

  Operations

13,632

11,103

2,529

  Depreciation and amortization

7,237

6,580

657

  General and administrative

1,508

1,848

(340)

22,377

19,531

2,846

Operating income

24,172

21,274

2,898

Equity in earnings of SLC Pipeline

570

711

(141)

Interest income

1

2

(1)

Interest expense, including amortization

(8,417)

(6,418)

(1,999)

Other income

9

-

9

(7,837)

(5,705)

(2,132)

Income from continuing operations before income taxes

16,335

15,569

766

State income tax

(76)

(100)

24

Income from continuing operations

16,259

15,469

790

Income from discontinued operations, net of noncontrolling

    interest of $269 (1)

-

1,070

(1,070)

Net income

16,259

16,539

(280)

Less general partner interest in net income, including incentive distributions (2)

3,172

2,022

1,150

Limited partners' interest in net income

$    13,087

$  14,517

$    (1,430)

Limited partners' earnings per unit – basic and diluted: (2)

  Income from continuing operations

$  0.59

$  0.73

$  (0.14)

  Income from discontinued operations

-

0.05

(0.05)

  Net income

$  0.59

$  0.78

$  (0.19)

Weighted average limited partners' units outstanding

22,079

18,520

3,559

EBITDA (3)

$    31,988

$  29,888

$    2,100

Distributable cash flow (4)

$    23,969

$  20,678

$    3,291

Volumes  from continuing operations (bpd) (1)

Pipelines:

  Affiliates – refined product pipelines

93,194

98,987

(5,793)

    Affiliates – intermediate pipelines

83,227

88,053

(4,826)

  Affiliates – crude pipelines

143,617

143,902

(285)

320,038

330,942

(10,904)

  Third parties – refined product pipelines

41,967

43,858

(1,891)

362,005

374,800

(12,795)

Terminals and loading racks:

  Affiliates

183,312

122,413

60,899

  Third parties

43,633

44,459

(826)

226,945

166,872

60,073

Total for pipelines and terminal assets (bpd)

588,950

541,672

47,278

Nine Months Ended

September 30,

Change from

2010

2009

2009

(In thousands, except per unit data)

Revenues

Pipelines:

  Affiliates – refined product pipelines

$    35,887

$  31,186

$    4,701

  Affiliates – intermediate pipelines

15,673

11,438

4,235

  Affiliates – crude pipelines

28,907

21,215

7,692

80,467

63,839

16,628

  Third parties – refined product pipelines

19,136

31,125

(11,989)

99,603

94,964

4,639

Terminals and loading racks:

  Affiliates

27,522

7,907

19,615

  Third parties

5,603

5,265

338

33,125

13,172

19,953

Total revenues

132,728

108,136

24,592

Operating costs and expenses:

  Operations

40,187

32,076

8,111

  Depreciation and amortization

22,038

19,209

2,829

  General and administrative

5,984

4,979

1,005

68,209

56,264

11,945

Operating income

64,519

51,872

12,647

Equity in earnings of SLC Pipeline

1,595

1,309

286

Interest income

6

10

(4)

Interest expense, including amortization

(25,510)

(16,225)

(9,285)

Other income

2

65

(63)

SLC Pipeline acquisition costs

-

(2,500)

2,500

(23,907)

(17,341)

(6,566)

Income from continuing operations before income taxes

40,612

34,531

6,081

State income tax

(216)

(266)

50

Income from continuing operations

40,396

34,265

6,131

Income from discontinued operations, net of noncontrolling interest of 1,191 (1)

-

4,105

(4,105)

Net income

40,396

38,370

2,026

Less general partner interest in net income, including incentive distributions (2)

8,727

5,163

3,564

-

Limited partners' interest in net income

$    31,669

$  33,207

$    (1,538)

Limited partners' earnings per unit – basic and diluted: (2)

  Income from continuing operations

$  1.43

$  1.66

$  (0.23)

  Income from discontinued operations

-

0.23

(0.23)

  Net income

$  1.43

$  1.89

$  (0.46)

Weighted average limited partners' units outstanding

22,079

17,546

4,533

EBITDA (3)

$    88,154

$  74,831

$    13,323

Distributable cash flow (4)

$    66,800

$  51,677

$    15,123

Volumes  from continuing operations (bpd) (1)

Pipelines:

  Affiliates – refined product pipelines

95,013

85,489

9,524

   Affiliates – intermediate pipelines

82,844

64,494

18,350

  Affiliates – crude pipelines

139,955

136,315

3,640

317,812

286,298

31,514

  Third parties – refined product pipelines

35,923

45,647

(9,724)

353,735

331,945

21,790

Terminals and loading racks:

  Affiliates

177,946

106,969

70,977

  Third parties

38,825

42,873

(4,048)

216,771

149,842

66,929

Total for pipelines and terminal assets (bpd)

570,506

481,787

88,719

(1)

On December 1, 2009, we sold our 70% interest in Rio Grande.  Results of operations of Rio Grande are presented in discontinued operations.  Pipeline volume information excludes volumes attributable to Rio Grande.

(2)

Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement.  Net income allocated to the general partner includes incentive distributions declared subsequent to quarter end.  General partner incentive distributions for the three and the nine months ended September 30, 2010 were $2.9 million and $8.1 million. For the three and the nine months ended September 30, 2009 the distributions were $1.7 million and $4.5 million, respectively.  Net income attributable to the limited partners is divided by the weighted average limited partner units outstanding in computing the limited partners' per unit interest in net income.

(3)

Earnings before interest, taxes, depreciation and amortization ("EBITDA") is calculated as net income plus (i) interest expense, net of interest income, (ii) state income tax and (iii) depreciation and amortization.  EBITDA is not a calculation based upon U.S. generally accepted accounting principles ("GAAP").  However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements, with the exception of EBITDA from discontinued operations.  EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity.  EBITDA is not necessarily comparable to similarly titled measures of other companies.  EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance.  EBITDA also is used by our management for internal analysis and as a basis for compliance with financial covenants.

Set forth below is our calculation of EBITDA.

Three Months Ended

September 30,

Nine Months Ended

September 30,

2010

2009

2010

2009

(In thousands)

Income from continuing operations

$    16,259

$    15,469

$    40,396

$    34,265

Add (subtract):

 Interest expense

8,135

5,314

22,230

15,396

 Amortization of discount and deferred

  debt issuance costs

       282

       176

       740

       529

 Increase in interest expense – change in

  fair value of interest rate swaps and

  swap settlement costs

-

928

2,540

300

 Interest income

(1)

(2)

(6)

(10)

 State income tax

76

100

216

266

 Depreciation and amortization

7,237

6,580

22,038

19,209

 EBITDA from discontinued operations

-

1,323

-

4,876

EBITDA

$    31,988

$    29,888

$    88,154

$    74,831

(4)

Distributable cash flow is not a calculation based upon GAAP.  However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of equity in excess cash flows over earnings of SLC Pipeline, maintenance capital expenditures and distributable cash flow from discontinued operations.  Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income, as an indication of our operating performance, or as an alternative to operating cash flow as a measure of liquidity.  Distributable cash flow is not necessarily comparable to similarly titled measures of other companies.  Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance.  It also is used by management for internal analysis and our performance units.  We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating.

Set forth below is our calculation of distributable cash flow.

Three Months Ended

September 30,

Nine Months Ended

September 30,

2010

2009

2010

2009

(In thousands)

Income from continuing operations

$    16,259

$    15,469

$    40,396

$    34,265

Add (subtract):

 Depreciation and amortization

7,237

6,580

22,038

19,209

 Amortization of discount and deferred

  debt issuance costs

       282

176

       740

       529

 Increase in interest expense –  change

  in fair value of interest rate swaps and

  swap settlement costs

-

       928

2,540

          300

 Equity in excess cash flows over

  earnings of SLC Pipeline

       173

167

       525

       387

  Increase (decrease) in deferred revenue

758

(3,407)

3,279

(8,076)

 SLC Pipeline acquisition costs*

-

-

-

2,500

 Maintenance capital expenditures**

(740)

(545)

(2,718)

(2,262)

 Distributable cash flow from

  discontinued operations

-

1,310

-

4,825

Distributable cash flow

$    23,969

$    20,678

$    66,800

$    51,677

*

We expensed the $2.5 million finder's fee associated with our joint venture agreement with Plains that closed in March 2009.   These costs directly relate to our interest in the new joint venture pipeline and are similar to expansion capital expenditures; accordingly, we have added back these costs to arrive at distributable cash flow.    

**

Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives.  Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, and safety and to address environmental regulations.

September 30,

December 31,

2010

2009

Balance Sheet  Data

(In thousands)

Cash and cash equivalents

$   706

$            2,508

Working capital (5)

$  (155,392)

$            4,404

Total assets

$  634,584

$        616,845

Long-term debt (6)

$  332,564

$        390,827

Total equity (7)

$  110,948

$        193,864

(5)

Our credit agreement expires in August 2011; therefore, working capital at September 30, 2010 reflects $157 million of credit agreement borrowings that are classified as current liabilities.  We intend to renew the credit agreement prior to expiration and to continue to finance the outstanding credit agreement balance, which we will then reclassify as long-term debt.  Excluding the $157 million credit agreement borrowings, working capital was $1.6 million at September 30, 2010.

(6)

Includes $206 million of credit agreement advances at December 31, 2009.

(7)

As a master limited partnership, we distribute our available cash, which historically has exceeded our net income because depreciation and amortization expense represents a non-cash charge against income.  The result is a decline in partners' equity since our regular quarterly distributions have exceeded our quarterly net income.  Additionally, if the assets transferred to us upon our initial public offering in 2004, the intermediate pipelines purchased from Holly in 2005 and the assets purchased from Holly in 2009 and March 2010 had been acquired from third parties, our acquisition cost in excess of Holly's basis in the transferred assets of $217.9 million would have been recorded as increases to our properties and equipment and intangible assets instead of decreases to partners' equity.

SOURCE Holly Energy Partners, L.P.



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