BreitBurn Energy Partners L.P. Reports Record Second Quarter Results

BreitBurn Energy Partners L.P. Reports Record Second Quarter Results

LOS ANGELES--(BUSINESS WIRE)-- BreitBurn Energy Partners L.P. (the "Partnership") (NAS: BBEP) today announced financial and operating results for its second quarter of 2013.

Selected Results for the Quarter Included the Following:

  • Increased total net production to a quarterly record high of 2.45 MMBoe, which represented a 26% increase from the second quarter of 2012.
  • Increased liquids production to a quarterly record high of 1.29 MMBoe, which represented a 58% increase from the second quarter of 2012.
  • Increased Adjusted EBITDA, a non-GAAP financial measure, to $84.8 million, which represented a 31% increase from the second quarter of 2012.
  • Drilled 38 wells and completed 21 workovers, which in total added incremental net initial production of approximately 1,925 Boe/day.
  • Declared a cash distribution for the second quarter of 2013 of $0.48 per unit, or $1.92 per unit on an annualized basis, on July 31, 2013, which represented a 4.3% increase from the second quarter of 2012.
  • Announced the acquisition of oil and gas properties and associated midstream assets in the Oklahoma Panhandle and New Mexico, which was completed on July 15, 2013 for a total cash price of $876 million, subject to customary purchase price adjustments.

Management Commentary

Hal Washburn, CEO, said: "The Partnership delivered excellent financial and operating results including record quarterly production and Adjusted EBITDA above our guidance range. The active development programs for our legacy and newly acquired assets continued to yield strong results this quarter. We are also very pleased to have announced and closed the acquisition of oil properties and associated midstream assets in the Mid-Continent for approximately $876 million. The acquisition immediately adds significant production to our portfolio and an increased focus on liquids. We expect these assets to provide substantial accretion to distributable cash flow per unit to support distribution growth."

Second Quarter 2013 Operating and Financial Results Compared to First Quarter 2013

  • Total production increased to a record quarterly high of 2,453 MBoe in the second quarter of 2013, up from 2,346 MBoe in the first quarter of 2013. Average daily production was 26,956 Boe/day in the second quarter of 2013 compared to 26,070 Boe/day in the first quarter of 2013.
    • Oil and NGL production was 1,287 MBoe compared to 1,206 MBoe in the first quarter of 2013
    • Natural gas production was 6,994 MMcf compared to 6,844 MMcf in the first quarter of 2013.
  • Adjusted EBITDA, a non-GAAP financial measure, was $84.8 million in the second quarter of 2013 compared to $64.1 million in the first quarter of 2013. The increase was primarily due to higher crude oil and natural gas sales volumes and higher average realized prices, better oil differentials in Wyoming and Texas, better natural gas differentials in Michigan and lower general and administrative expenses.
  • Pre-tax lease operating expenses, which include district expenses, processing fees and transportation costs, were $19.79 per Boe in the second quarter of 2013 compared to $19.42 per Boe in the first quarter of 2013.
  • General and administrative expenses, excluding non-cash unit-based compensation, were $3.56 per Boe in the second quarter of 2013 compared to $4.29 per Boe in the first quarter of 2013.
  • Oil, NGL, and natural gas sales revenues were $149.3 million for the second quarter of 2013, up from $120.4 million in the first quarter of 2013, primarily reflecting higher crude oil sales volumes, and higher natural gas prices.
  • Gains on commodity derivative instruments were $67.0 million in the second quarter of 2013 compared to losses of $24.2 million in the first quarter of 2013, which primarily reflects a decrease in crude oil and natural gas future prices during the second quarter of 2013. Derivative instrument settlements received were $4.8 million in the second quarter of 2013 compared to $5.2 million in the first quarter of 2013.
  • NYMEX WTI crude oil spot prices averaged $94.05 per barrel and Brent crude oil spot prices averaged $102.57 per barrel in the second quarter of 2013 compared to $94.33 per barrel and $112.47 per barrel, respectively, in the first quarter of 2013. Henry Hub natural gas spot prices averaged $4.02 per Mcf in the second quarter of 2013 compared to $3.49 per Mcf in the first quarter of 2013.
  • Realized crude oil and NGL prices, excluding the effects of commodity derivative settlements, averaged $87.82 per Boe and realized natural gas prices, excluding the effects of commodity instruments, averaged $4.22 per Mcf in the second quarter of 2013, compared to $84.61 per Boe and $3.61 per Mcf, respectively, in the first quarter of 2013.
  • Net income attributable to the Partnership, including the effect of derivative instruments, was $76.4 million, or $0.75 per diluted common unit, in the second quarter of 2013, compared to a net loss of $36.3 million, or $0.38 per diluted common unit, in the first quarter of 2013.
  • Oil and gas capital expenditures totaled $65 million in the second quarter of 2013 compared to $45 million in the first quarter of 2013.

Impact of Derivative Instruments

The Partnership uses commodity derivative instruments to mitigate the risks associated with commodity price volatility and to help maintain cash flows for operating activities, acquisitions, capital expenditures and distributions. The Partnership does not enter into derivative instruments for speculative trading purposes. Because the Partnership does not use hedge accounting to account for its derivative instruments, changes in the fair value of derivative instruments are recorded in earnings each reporting period. These non-cash changes in the fair value of derivatives do not affect Adjusted EBITDA, cash flow from operations or the Partnership's ability to pay cash distributions for the reporting periods presented.

Total gains from commodity derivative instruments were approximately $67.0 million for the quarter ended June 30, 2013, which include $4.8 million for contracts that settled during the period.

Production, Statement of Operations, and Realized Price Information

The following table presents production, selected income statement and realized price information for the three months ended June 30, 2013 and 2012, and the three months ended March 31, 2013:

   Three Months Ended
June 30,   March 31,   June 30,
Thousands of dollars, except as indicated201320132012
Oil, natural gas and NGL sales (a)$149,286$120,362$94,981
Gain (loss) on commodity derivatives instruments66,993(24,176)107,288
Other revenues, net 702 758  907
Total revenues$216,981$96,944 $203,176
Lease operating expenses and processing fees$48,544$45,561$39,122
Production and property taxes 11,066 9,383  6,525
Total lease operating expenses$59,610$54,944 $45,647
Purchases and other operating costs337318647
Change in inventory 1,287 (3,109) 2,600
Total operating costs$61,234$52,153 $48,894
Lease operating expenses, pre taxes, per Boe (b)$19.79$19.42$20.03
Production and property taxes per Boe4.514.003.34
Total lease operating expenses per Boe 24.30 23.42  23.37
General and administrative expenses (excluding unit-based compensation)$8,727$10,055 $7,314
Net income (loss) attributable to the partnership$76,432$(36,300)$92,506
Net income (loss) per diluted limited partner unit$0.75$(0.38)$1.29
 
Total production (MBoe)2,4532,3461,953
Oil and NGL (MBoe)1,2871,206815
Natural gas (MMcf)6,9946,8446,824
Average daily production (Boe/d) 26,956 26,070  21,457
Sales volumes (MBoe) 2,528 2,270  2,013
Average realized sales price (per Boe) (c) (d)$58.98$52.96$47.08
Oil and NGL (per Boe) (c) (d)87.8284.6190.05
Natural gas (per Mcf) (c) 4.22 3.61  2.33
 
(a) NGLs account for 5% or less of total production.
(b) Includes lease operating expenses, district expenses, transportation expenses and processing fees.
(c) Excludes the effect of commodity derivative settlements.
(d) Includes crude oil purchases.
 

Non-GAAP Financial Measures

This press release, the financial tables and other supplemental information, including the reconciliations of certain non-generally accepted accounting principles ("non-GAAP") measure to their nearest comparable generally accepted accounting principles ("GAAP") measures, may be used periodically by management when discussing the Partnership's financial results with investors and analysts, and they are also available on the Partnership's website under the Investor Relations tab.

Among the non-GAAP financial measures used is "Adjusted EBITDA." This non-GAAP financial measure should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. Management believes that these non-GAAP financial measures enhance comparability to prior periods.

Adjusted EBITDA is presented as management believes it provides additional information relative to the performance of the Partnership's business, such as our ability to meet our debt covenant compliance tests. This non-GAAP financial measure may not be comparable to similarly titled measures of other publicly traded partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner.

Adjusted EBITDA

The following table presents a reconciliation of net income and net cash flows from operating activities, our most directly comparable GAAP financial performance and liquidity measures, to Adjusted EBITDA for each of the periods indicated.

   Three Months Ended
June 30,  March 31,  June 30,
Thousands of dollars201320132012 (a)
Reconciliation of net income (loss) to Adjusted EBITDA:
 
Net income (loss) attributable to the Partnership$76,432$(36,300)$92,506
 
(Gain) loss on commodity derivative instruments(66,993)24,176(107,288)
Commodity derivative instrument settlements (b) (c)4,7985,15825,063
Depletion, depreciation and amortization expense46,54147,79033,517
Interest expense and other financing costs18,42018,41914,069
Loss on interest rate swaps (d)--190
(Gain) loss on sale of assets71(9)29
Income tax expense (benefit)574301,005
Unit-based compensation expense (e) 4,989  4,808  5,612 
Adjusted EBITDA$84,832 $64,072 $64,703 
 
 
Three Months Ended
June 30,March 31,June 30,
Thousands of dollars201320132012 (a)
 
Reconciliation of net cash flows from operating activities to Adjusted EBITDA:
 
Net cash provided by operating activities$38,570$58,852$29,252
 
Increase (decrease) in assets net of liabilities relating to operating activities29,074(12,140)21,940
Interest expense (d) (f)17,06217,18013,583
Income from equity affiliates, net(130)129(155)
Income taxes25651100
Non-controlling interest -  -  (17)
Adjusted EBITDA$84,832 $64,072 $64,703 
 
(a) Adjusted EBITDA for the three months ended June 30, 2012 was conformed to exclude $1.6 million related to "Net operating cash flow from acquisitions, effective date through closing date."
(b) Excludes pre-paid premiums, paid in 2012, related to crude oil derivatives that settled during the three months ended June 30, 2013 and March 31, 2013 of $1.2 million and $1.2 million, respectively. There were no pre-paid premiums associated with contract settlements in the three months ended June 30, 2012.
(c) For the three months ended June 30, 2013, March 31, 2013 and June 30, 2012, includes settlements received (paid) on crude oil derivatives of $(3.6) million, $(7.3) million and $1.8 million, respectively, and settlements received on natural gas derivatives of $8.4 million, $12.5 million and $23.3 million, respectively.
(d) Includes settlements paid on interest rate derivatives.
(e) Represents non-cash long-term unit-based incentive compensation expense.
(f) Excludes amortization of debt issuance costs and amortization of senior note discount/premium.
 

Hedge Portfolio Summary

The table below summarizes the Partnership's commodity derivative hedge portfolio as of August 5, 2013. Please refer to the updated Commodity Price Protection Portfolio via our website for additional details related to our hedge portfolio.

   

Year

2013   2014   2015   2016   2017   2018
Oil Positions:
Fixed Price Swaps - NYMEX WTI

Hedged Volume (Bbls/d)

13,23111,31410,1896,7115,471493
Average Price ($/Bbl)$95.24$93.67$94.71$86.97$83.38$82.20
Fixed Price Swaps - ICE Brent
Hedged Volume (Bbls/d)4,2004,8003,3004,300298-
Average Price ($/Bbl)$97.57$98.88$97.73$95.17$97.50$-
Collars - NYMEX WTI
Hedged Volume (Bbls/d)5001,0001,000---
Average Floor Price ($/Bbl)$77.00$90.00$90.00$-$-$-
Average Ceiling Price ($/Bbl)$103.10$112.00$113.50
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