Delaware (State or other jurisdiction of incorporation or organization) | 001-33055 (Commission File Number) | 74-3169953 (I.R.S. Employer Identification No.) |
o | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
o | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
o | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
o | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Exhibit No. | Exhibit Description | |
99.1 | Breitburn Energy Partners LP fourth quarter 2015 earnings release dated February 26, 2016. |
BREITBURN ENERGY PARTNERS LP | ||
By: | BREITBURN GP, LLC, | |
its general partner | ||
Dated: February 26, 2016 | By: | /s/ James G. Jackson |
James G. Jackson | ||
Chief Financial Officer |
• | Annual production of 20.2 million Boe, at high-end of guidance, with average daily production of 55,288 Boe/d for the year. |
• | Adjusted EBITDA, a non-GAAP financial measure, increased to $169 million in 4Q15, 8.2% higher than 3Q15, despite lower realized oil and NGL prices. 2015 Adjusted EBITDA of $636.8 million (including acquisition and integration costs of $12.6 million and restructuring costs of $5 million) was in line with guidance. |
• | Pre-tax lease operating expenses were $17.74/Boe in 4Q15, 10.5% lower than 3Q15 and 18.5% lower than 4Q14. 2015 pre-tax lease operating expenses were $19.02/Boe, at low-end of guidance. |
• | G&A expenses, excluding acquisition and integration costs and non-cash unit based compensation, were $2.48/Boe in 4Q15, 9.4% lower than 3Q15 and the best quarter in Breitburn’s history. 2015 G&A expenses, excluding acquisition and integration costs and non-cash unit based compensation, were $3.02/Boe, 13% lower than 2014. |
• | The estimated fair value of Breitburn’s commodity hedge portfolio was approximately $666 million as of December 31, 2015. |
• | Total production was 5,106 MBoe in the fourth quarter of 2015 compared to 5,008 MBoe in the third quarter of 2015. Average daily production was 55.5 MBoe/day in the fourth quarter of 2015 compared to 54.4 MBoe/day in the third quarter of 2015. |
• | Oil production increased to 2,795 MBbl compared to 2,741 MBbl in the third quarter of 2015 |
• | NGL production increased to 526 MBbl compared to 485 MBbl in the third quarter of 2015 |
• | Natural gas production increased to 10,712 MMcf compared to 10,689 MMcf in the third quarter of 2015 |
• | Adjusted EBITDA was $169 million in the fourth quarter of 2015 compared to $156.3 million in the third quarter of 2015, an 8.2% increase. The increase was primarily due to higher commodity derivative instrument settlement receipts, lower operating costs, higher sales volume, and lower G&A expenses, partially offset by lower oil, natural gas and NGL sales revenue due to lower average realized commodity prices. |
• | Net loss attributable to common unitholders was $902.3 million, or $4.25 per diluted common unit, in the fourth quarter of 2015, which included non-cash impairment charges of approximately $878.3 million, or $4.14 per common unit, primarily related to the impact that further deterioration in forecast future commodity prices had on our projected net revenues for certain of our oil and gas properties, compared to net loss of $1.3 billion, or $6.17 per diluted common unit, in the third quarter of 2015, which included non-cash impairment charges of approximately $1.4 billion, or $6.80 per unit. |
• | Oil, NGL and natural gas sales revenues were $139.7 million in the fourth quarter of 2015 compared to $153.3 million in the third quarter of 2015, primarily due to lower realized oil and natural gas prices, partially offset by higher sales volumes. |
• | Lease operating expenses, which include district expenses, processing fees, and transportation costs but exclude taxes, were $17.74 per Boe in the fourth quarter of 2015 compared to $19.83 per Boe in the third quarter of 2015. The decrease was due to lower operating costs, lower workover expenses and continued focus on lowering costs. |
• | General and administrative expenses, excluding non-cash unit-based compensation costs, were $14.5 million in the fourth quarter of 2015 (including acquisition and integration costs of $1.8 million) compared to $16.9 million in the third quarter of 2015 (including acquisition and integration costs of $3.2 million). The decrease was primarily due to lower integration costs and lower employee related expenses. |
• | Gains on commodity derivative instruments were $141.8 million in the fourth quarter of 2015 compared to gains of $253 million in the third quarter of 2015, primarily due to increases in oil and natural gas futures prices during the fourth quarter of 2015. Derivative instrument settlement receipts were $144.1 million in the fourth quarter of 2015 compared to receipts of $129 million in the third quarter of 2015, primarily due to lower oil prices. |
• | NYMEX WTI oil spot prices averaged $41.94 per Bbl and Brent oil spot prices averaged $43.56 per Bbl in the fourth quarter of 2015 compared to $46.64 per Bbl and $50.41 per Bbl, respectively, in the third quarter of 2015. Henry Hub natural gas spot prices averaged $2.12 per Mcf in the fourth quarter of 2015 compared to $2.76 per Mcf in the third quarter of 2015. |
• | Average realized crude oil, NGL, and natural gas prices, excluding the effects of commodity derivative settlements, averaged $37.31 per Bbl, $13.03 per Bbl and $2.32 per Mcf, respectively, in the fourth quarter of 2015 compared to $43.38 per Bbl, $12.44 per Bbl and $2.76 per Mcf, respectively, in the third quarter of 2015. |
• | Oil, NGL and natural gas capital expenditures were approximately $36 million in the fourth quarter of 2015 compared to $46 million in the third quarter of 2015. |
• | Total production was 20.2 million Boe in 2015 compared to 14.1 million Boe in 2014. Production volumes increased by 6.1 million Boe, or 43%, primarily due to production from properties acquired in the QRE merger. |
• | Adjusted EBITDA was $636.8 million in 2015 (including acquisition and integration costs of $12.6 million and restructuring costs of $5 million) compared to $473.8 million in 2014. The increase reflects the full year effect of the QRE merger, higher commodity derivative instrument settlement receipts and lower operating costs, partially offset by lower oil, natural gas and NGL sales revenue due to lower average realized commodity prices. |
• | Net loss attributable to common unitholders was $2.6 billion, or $12.39 per diluted common unit, in 2015, which included non-cash impairment charges of approximately $2.4 billion, or $11.24 per common unit, compared to a net income of $411.3 million, or $3.02 per diluted common unit, in 2014, which included non-cash impairment charges of approximately $149 million, or $1.11 per common unit. |
• | Total oil, NGL and natural gas sales were $645.3 million in 2015, a decrease of 25% from 2014 primarily due to lower commodity prices, partially offset by higher volumes from the full year effect of production from properties acquired in the QRE merger. |
• | Lease operating expenses, which include district expenses, processing fees, and transportation costs but exclude taxes, were $383.8 million compared to $291.4 million in 2014, reflecting the full year effect of lease operating costs from properties acquired in the QRE merger. |
• | General and administrative expenses, excluding unit-based compensation related costs but including $12.6 million in acquisition and integration costs, were $73.5 million compared to $63.6 million in 2014, which included $14 million in acquisition and integration costs. The increase was primarily due to higher payroll expense for additional personnel attributable to the QRE merger. |
• | Gains on commodity derivative instruments were $438.6 million in 2015 compared to gains of $566.5 million in 2014. Derivative instrument settlement receipts were $500 million in 2015 compared to receipts of $27.8 million in 2014, primarily due to lower oil prices. |
• | Average realized oil and NGL prices, excluding the effect of commodity derivative instruments, for 2015, were $44.46 per Bbl and $15.02 per Bbl, respectively, compared to NYMEX WTI oil prices of $48.49 per barrel. Average realized natural gas prices, excluding the effect of commodity derivative instruments, were $2.67 per Mcf compared to Henry Hub prices of $2.62 per Mcf. |
Operating Area | % Estimated Proved Reserves | |
Midwest | 21.5% | |
Ark-La-Tex | 19.6% | |
Permian Basin | 18.7% | |
Mid-Continent | 13.5% | |
Rockies | 10.7% | |
Southeast | 8.5% | |
California | 7.5% |
($ in 000s) | 2016 Operational Guidance (1) | ||||||
Total Production (MBoe): | 17,000 | — | 19,700 | ||||
Oil Production (MBbls) | 9,000 | — | 10,500 | ||||
NGL Production (MBbls) | 1,750 | — | 1,950 | ||||
Natural Gas Production (MMcfe) | 37,500 | — | 43,500 | ||||
Average Price Differential %: | |||||||
WTI Oil Price Differential % | 85.0 | % | — | 93.0% | |||
NGL Price Differential % (of WTI) | 30.0% | — | 50.0% | ||||
Natural Gas Price Differential % | 100.0% | — | 105.0% | ||||
Oil, NGL, and Natural Gas Sales Revenue (2) | $330,000 | — | $430,000 | ||||
Other Revenue (3) | $25,000 | — | $33,000 | ||||
Lease Operating Expenses / Boe (4) | $18.00 | — | $20.00 | ||||
Other Operating Expenses (5) | $16,000 | — | $18,000 | ||||
Production / Property Taxes (% of Sales Revenue) | 8.00% | — | 8.50% | ||||
G&A (Excluding Unit Based Compensation) (6) | $56,000 | — | $60,000 | ||||
Adjusted EBITDA (7) | $490,000 | — | $525,000 | ||||
Cash Interest Expense (8) | $191,000 | — | $197,000 | ||||
Preferred Equity Distributions (9) | $16,500 | ||||||
Capital Expenditures (10) | $80,000 |
(1) | Breitburn’s 2016 Operational Guidance is based on flat $30 per barrel WTI crude oil, $30 per barrel Brent crude oil and $2.30 per Mcf natural gas prices and excludes acquisitions, divestitures or financing transactions. Operating costs and capital expenditures generally track commodity prices but they do not increase or decrease as quickly as commodity prices. |
(2) | Range based on the low and high values of production and differentials as set forth above. |
(3) | Primarily consists of other revenues from the East Texas Salt Water Disposal System and the Postle Field in OK. |
(4) | Pre-tax lease operating expenses include processing fees, district expenses, and transportation costs. |
(5) | Represents costs related to the East Texas Salt Water Disposal System. |
(6) | Excludes approximately $10 million in long-term compensation and severance payments paid in cash. |
(7) | Assuming the high and low ranges of production and LOE guidance (and the midpoint for the remaining guidance components), Adjusted EBITDA is expected to range between $490 million and $525 million, and is comprised of estimated net loss (before non-cash compensation and non-cash distributions paid-in-kind to holders of 8% Series B Preferred Units) between ($541) million (low end of Adjusted EBITDA) and ($500) million (high end of Adjusted EBITDA), plus unrealized losses on commodity derivative instruments of $385 million, plus DD&A of $433 million, plus interest expense between $191 million (high end of Adjusted EBITDA) and $197 million (low end of Adjusted EBITDA), plus preferred distributions to holders of 8.25% Series A Preferred Units of $16.5 million. Differences between actual and forecast prices could result in changes to unrealized gains or losses on commodity derivative instruments, DD&A, including potential impairments of long-lived assets, and ultimately, net income. |
(8) | Typically, Breitburn’s borrowings under its credit facility are based on 1-month LIBOR plus an applicable spread ranging from 175 bps to 275 bps. Cash interest expense assumes a 1-month LIBOR rate of 0.50%. |
(9) | Reflects cash distributions paid to holders of 8.25% Series A Cumulative Redeemable Perpetual Preferred Units and assumes that distributions owed to holders of 8% Series B Perpetual Convertible Preferred Units will be paid in kind. |
(10) | Capital expenditures exclude information technology spending of $1.7 million and capitalized engineering of $4.3 million. |
Three Months Ended | Year Ended | |||||||||||||||||||
December 31, | September 30, | December 31, | December 31, | |||||||||||||||||
Thousands of dollars, except as indicated | 2015 | 2015 | 2014 | 2015 | 2014 | |||||||||||||||
Oil sales | $ | 108,024 | $ | 117,743 | $ | 151,335 | $ | 504,035 | $ | 669,355 | ||||||||||
NGL sales | 6,852 | 6,032 | 9,709 | 29,336 | 41,031 | |||||||||||||||
Natural gas sales | 24,812 | 29,550 | 36,023 | 111,901 | 145,434 | |||||||||||||||
Gain on commodity derivative instruments | 141,842 | 253,012 | 587,590 | 438,614 | 566,533 | |||||||||||||||
Other revenues, net | 5,934 | 5,922 | 3,376 | 24,829 | 7,616 | |||||||||||||||
Total revenues | 287,464 | 412,259 | 788,033 | 1,108,715 | 1,429,969 | |||||||||||||||
Lease operating expenses (a) | 90,563 | 99,318 | 90,768 | 383,827 | 291,395 | |||||||||||||||
Production and property taxes (b) | 9,033 | 13,249 | 14,084 | 51,174 | 62,071 | |||||||||||||||
Total lease operating expenses | 99,596 | 112,567 | 104,852 | 435,001 | 353,466 | |||||||||||||||
Purchases and other operating costs | 2,119 | 367 | 299 | 3,056 | 725 | |||||||||||||||
Salt water disposal costs | 2,408 | 4,205 | 2,168 | 14,687 | 2,168 | |||||||||||||||
Change in inventory | 2,116 | (2,004 | ) | 201 | 2,445 | (678 | ) | |||||||||||||
Total operating costs | 106,239 | 115,135 | 107,520 | 455,189 | 355,681 | |||||||||||||||
Lease operating expenses, pre taxes, per Boe (a) | $ | 17.74 | $ | 19.83 | $ | 21.77 | $ | 19.02 | $ | 20.65 | ||||||||||
Production and property taxes per Boe (b) | 1.77 | 2.65 | 3.38 | 2.54 | 4.40 | |||||||||||||||
Total lease operating expenses per Boe | 19.51 | 22.48 | 25.15 | 21.56 | 25.05 | |||||||||||||||
General and administrative expenses (excluding non-cash unit-based compensation) | 14,508 | 16,916 | 28,116 | 73,537 | 63,562 | |||||||||||||||
Net (loss) income attributable to the partnership | (890,878 | ) | (1,327,929 | ) | 405,173 | (2,583,339 | ) | 421,333 | ||||||||||||
Basic net (loss) income per unit | $ | (4.25 | ) | $ | (6.17 | ) | $ | 2.28 | $ | (12.39 | ) | $ | 3.04 | |||||||
Diluted net (loss) income per unit | $ | (4.25 | ) | $ | (6.17 | ) | $ | 2.27 | $ | (12.39 | ) | $ | 3.02 | |||||||
Total production (MBoe) (c) | 5,106 | 5,008 | 4,170 | 20,180 | 14,114 | |||||||||||||||
Oil (MBbl) | 2,795 | 2,741 | 2,327 | 11,248 | 7,931 | |||||||||||||||
NGLs (MBbl) | 526 | 485 | 368 | 1,953 | 1,157 | |||||||||||||||
Natural gas (MMcf) | 10,712 | 10,689 | 8,847 | 41,876 | 30,159 | |||||||||||||||
Average daily production (Boe/d) | 55,500 | 54,435 | 45,313 | 55,288 | 38,670 | |||||||||||||||
Sales volumes (MBoe) (d) | 5,151 | 4,980 | 4,022 | 20,219 | 13,956 | |||||||||||||||
Average realized sales price (per Boe) (e) (f) | $ | 26.72 | $ | 30.78 | $ | 48.96 | $ | 31.80 | $ | 61.30 | ||||||||||
Oil (per Bbl) (e) (f) | 37.31 | 43.38 | 69.36 | 44.46 | 86.08 | |||||||||||||||
NGLs (per Bbl) (e) | 13.03 | 12.44 | 26.38 | 15.02 | 35.46 | |||||||||||||||
Natural gas (per Mcf) (e) | $ | 2.32 | $ | 2.76 | $ | 4.07 | $ | 2.67 | $ | 4.82 |
(a) | Includes district expenses, processing fees, and transportation expenses. | |||||
(b) | Includes ad valorem and severance taxes. | |||||
(c) | Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a Bbl of oil equivalent for natural gas is significantly less than the price for a Bbl of oil. | |||||
(d) | Oil sales were 2,841 MBbl, 2,713 MBbl and 2,180 MBbl for the three months ended December 31, 2015, September 30, 2015 and December 31, 2014, respectively, and 11,287 MBbl and 7,773 MBbl for the twelve months ended December 31, 2015 and 2014, respectively. | |||||
(e) | Excludes the effect of commodity derivative settlements. | |||||
(f) | Includes oil purchases. |
Three Months Ended | Year Ended | |||||||||||||||||||
December 31, | September 30, | December 31, | December 31, | |||||||||||||||||
Thousands of dollars, except as indicated | 2015 | 2015 | 2014 | 2015 | 2014 | |||||||||||||||
Reconciliation of net income (loss) to Adjusted EBITDA: | ||||||||||||||||||||
Net (loss) income attributable to the partnership | $ | (890,878 | ) | $ | (1,327,929 | ) | $ | 405,173 | $ | (2,583,339 | ) | $ | 421,333 | |||||||
Gain on commodity derivative instruments | (141,842 | ) | (253,012 | ) | (587,590 | ) | (438,614 | ) | (566,533 | ) | ||||||||||
Commodity derivative instrument settlements (a) (b) | 144,083 | 128,969 | 62,053 | 499,985 | 27,825 | |||||||||||||||
Depletion, depreciation and amortization expense | 123,312 | 117,464 | 87,292 | 460,047 | 291,709 | |||||||||||||||
Impairment of oil and natural gas properties | 878,335 | 1,440,167 | 119,566 | 2,377,615 | 149,000 | |||||||||||||||
Impairment of goodwill | — | — | — | 95,947 | — | |||||||||||||||
Interest expense and other financing costs | 50,319 | 51,915 | 36,110 | 205,718 | 126,470 | |||||||||||||||
(Gain) loss on sale of assets | (1,542 | ) | (7,459 | ) | 306 | (8,864 | ) | 663 | ||||||||||||
Income tax expense (benefit) | 1,162 | 14 | (457 | ) | 1,527 | (73 | ) | |||||||||||||
Unit-based compensation expense (c) | 6,091 | 6,360 | 4,947 | 25,462 | 23,387 | |||||||||||||||
Restructuring costs - unit-based compensation | — | (192 | ) | — | 1,343 | — | ||||||||||||||
Adjusted EBITDA | 169,040 | 156,297 | 127,400 | 636,827 | 473,781 | |||||||||||||||
Less: | ||||||||||||||||||||
Maintenance capital (d) | $ | 51,000 | $ | 52,000 | $ | 43,714 | $ | 200,000 | $ | 133,079 | ||||||||||
Cash interest expense | 48,374 | 48,654 | 35,651 | 184,007 | 120,470 | |||||||||||||||
Distributions to preferred unitholders | 4,125 | 4,125 | 4,125 | 16,500 | 10,083 | |||||||||||||||
Distributable cash flow available to common unitholders | $ | 65,541 | $ | 51,518 | $ | 43,910 | $ | 236,320 | $ | 210,149 | ||||||||||
Distributable cash flow available per common unit (e) (f) | $ | 0.296 | $ | 0.237 | $ | 0.207 | $ | 1.086 | $ | 1.431 | ||||||||||
Common unit distribution coverage (f) | n/a | 1.90x | 0.83x | 3.26x | 0.81x | |||||||||||||||
Reconciliation of net cash flows from operating activities to Adjusted EBITDA: | ||||||||||||||||||||
Net cash provided by operating activities | $ | 85,521 | $ | 136,239 | $ | 62,839 | $ | 436,705 | $ | 357,755 | ||||||||||
Increase (decrease) in assets net of liabilities relating to operating activities | 35,665 | (29,063 | ) | 29,199 | 16,369 | (4,057 | ) | |||||||||||||
Interest expense (g) | 48,364 | 48,562 | 35,563 | 183,852 | 120,143 | |||||||||||||||
Income from equity affiliates, net | 94 | 163 | (88 | ) | 104 | (178 | ) | |||||||||||||
Noncontrolling interest | (202 | ) | (91 | ) | 17 | (326 | ) | 17 | ||||||||||||
Income taxes | (413 | ) | 488 | (130 | ) | 258 | 101 | |||||||||||||
Gain on marketable securities | 11 | — | — | (135 | ) | — | ||||||||||||||
Adjusted EBITDA | $ | 169,040 | $ | 156,297 | $ | 127,400 | $ | 636,827 | $ | 473,781 |
(a) | Excludes premiums paid at contract inception related to those derivative contracts that settled during the applicable periods of: | $ | 1,682 | $ | 1,681 | $ | 2,141 | $ | 6,672 | $ | 8,494 | ||||||||||
(b) | Includes net cash settlements on derivative instruments for: | ||||||||||||||||||||
- Oil settlements received: | 123,492 | 112,437 | 55,975 | 431,073 | 18,230 | ||||||||||||||||
- Natural gas settlements received: | 20,592 | 16,532 | 6,078 | 68,913 | 9,595 | ||||||||||||||||
(c) | Represents non-cash long-term unit-based incentive compensation expense. | ||||||||||||||||||||
(d) | Maintenance capital is management's estimate of the investment in capital projects and obligatory spending on existing facilities and operations needed to hold production approximately flat over a multi-year period. | ||||||||||||||||||||
(e) | Based on common units outstanding (including outstanding LTIP grants) at each distribution record date within the periods. | ||||||||||||||||||||
(f) | Third quarter 2014 includes the effect of the offering of 14 million common units in October 2014. Fourth quarter 2014 includes only 41 days of QR Energy operating results, $11.7 million of acquisition and integration costs, and the effect of 71.5 million common units issued in connection with the QR Energy merger. | ||||||||||||||||||||
(g) | Excludes amortization of debt issuance costs and amortization of senior note discount/premium. |
Year | ||||||||||||||||
2016 | 2017 | 2018 | 2019 | |||||||||||||
Oil Positions: | ||||||||||||||||
Fixed Price Swaps - NYMEX WTI | ||||||||||||||||
Volume (Bbl/d) | 17,504 | 14,519 | 1,493 | 1,000 | ||||||||||||
Average Price ($/Bbl) | $ | 83.62 | $ | 82.81 | $ | 64.02 | $ | 56.35 | ||||||||
Fixed Price Swaps - ICE Brent | ||||||||||||||||
Volume (Bbl/d) | 4,300 | 298 | — | — | ||||||||||||
Average Price ($/Bbl) | $ | 95.17 | $ | 97.50 | $ | — | $ | — | ||||||||
Collars - NYMEX WTI | ||||||||||||||||
Volume (Bbl/d) | 1,500 | — | — | — | ||||||||||||
Average Floor Price ($/Bbl) | $ | 80.00 | $ | — | $ | — | $ | — | ||||||||
Average Ceiling Price ($/Bbl) | $ | 102.00 | $ | — | $ | — | $ | — | ||||||||
Collars - ICE Brent | ||||||||||||||||
Volume (Bbl/d) | 500 | — | — | — | ||||||||||||
Average Floor Price ($/Bbl) | $ | 90.00 | $ | — | $ | — | $ | — | ||||||||
Average Ceiling Price ($/Bbl) | $ | 101.25 | $ | — | $ | — | $ | — | ||||||||
Puts - NYMEX WTI | ||||||||||||||||
Volume (Bbl/d) | 1,000 | — | — | — | ||||||||||||
Average Price ($/Bbl) | $ | 90.00 | $ | — | $ | — | $ | — | ||||||||
Total: | ||||||||||||||||
Volume (Bbl/d) | 24,804 | 14,817 | 1,493 | 1,000 | ||||||||||||
Average Price ($/Bbl) | $ | 85.79 | $ | 83.11 | $ | 64.02 | $ | 56.35 | ||||||||
Gas Positions: | ||||||||||||||||
Fixed Price Swaps - MichCon City-Gate | ||||||||||||||||
Volume (MMBtu/d) | 29,000 | 24,000 | 17,500 | 10,000 | ||||||||||||
Average Price ($/MMBtu) | $ | 3.91 | $ | 3.71 | $ | 3.10 | $ | 3.15 | ||||||||
Fixed Price Swaps - Henry Hub | ||||||||||||||||
Volume (MMBtu/d) | 42,050 | 21,016 | 2,870 | — | ||||||||||||
Average Price ($/MMBtu) | $ | 4.02 | $ | 4.29 | $ | 3.74 | $ | — | ||||||||
Collars - Henry Hub | ||||||||||||||||
Volume (MMBtu/d) | 630 | 595 | — | — | ||||||||||||
Average Floor Price ($/MMBtu) | $ | 4.00 | $ | 4.00 | $ | — | $ | — | ||||||||
Average Ceiling Price ($/MMBtu) | $ | 5.55 | $ | 6.15 | $ | — | $ | — | ||||||||
Puts - Henry Hub | ||||||||||||||||
Volume (MMBtu/d) | 11,350 | 10,445 | — | — | ||||||||||||
Average Price ($/MMBtu) | $ | 4.00 | $ | 4.00 | $ | — | $ | — | ||||||||
Deferred Premium ($/MMBtu) | $ | 0.66 | (a) | $ | 0.69 | (b) | $ | — | $ | — | ||||||
Total: | ||||||||||||||||
Volume (MMBtu/d) | 83,030 | 56,056 | 20,370 | 10,000 | ||||||||||||
Average Price ($/MMBtu) | $ | 3.98 | $ | 3.98 | $ | 3.19 | $ | 3.15 |
Year | ||||||||||||||||
Thousands of dollars | 2016 | 2017 | 2018 | 2019 | ||||||||||||
Oil | $ | 7,438 | $ | 734 | $ | — | $ | — | ||||||||
Natural gas | 952 | — | — | — |
December 31, | December 31, | |||||||
Thousands of dollars | 2015 | 2014 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash | $ | 10,464 | $ | 12,628 | ||||
Accounts and other receivables, net | 128,589 | 166,436 | ||||||
Derivative instruments | 439,627 | 408,151 | ||||||
Related party receivables | 2,274 | 2,462 | ||||||
Inventory | 926 | 3,727 | ||||||
Prepaid expenses | 6,447 | 7,304 | ||||||
Total current assets | 588,327 | 600,708 | ||||||
Equity investments | 6,567 | 6,463 | ||||||
Property, plant and equipment | ||||||||
Oil and natural gas properties | 7,898,117 | 7,736,409 | ||||||
Other property, plant and equipment | 188,795 | 60,533 | ||||||
8,086,912 | 7,796,942 | |||||||
Accumulated depletion and depreciation | (4,154,030 | ) | (1,342,741 | ) | ||||
Net property, plant and equipment | 3,932,882 | 6,454,201 | ||||||
Other long-term assets | ||||||||
Goodwill | — | 92,024 | ||||||
Derivative instruments | 226,764 | 319,560 | ||||||
Other long-term assets | 117,872 | 165,378 | ||||||
Total assets | $ | 4,872,412 | $ | 7,638,334 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities | ||||||||
Accounts payable | $ | 50,412 | $ | 129,270 | ||||
Current portion of long-term debt | 154,000 | 105,000 | ||||||
Derivative instruments | 4,462 | 5,457 | ||||||
Distributions payable | 733 | 733 | ||||||
Current portion of asset retirement obligation | 2,341 | 4,948 | ||||||
Revenue and royalties payable | 35,462 | 40,452 | ||||||
Wages and salaries payable | 21,654 | 22,322 | ||||||
Accrued interest payable | 19,517 | 20,672 | ||||||
Production and property taxes payable | 24,292 | 25,207 | ||||||
Other current liabilities | 5,133 | 7,495 | ||||||
Total current liabilities | 318,006 | 361,556 | ||||||
Credit facility | 1,075,000 | 2,089,500 | ||||||
Senior notes, net | 1,789,219 | 1,156,560 | ||||||
Other long-term debt | 2,938 | 1,100 | ||||||
Total long-term debt | 2,867,157 | 3,247,160 | ||||||
Deferred income taxes | 3,844 | 2,575 | ||||||
Asset retirement obligation | 252,037 | 233,463 | ||||||
Derivative instruments | 255 | 2,269 | ||||||
Other long-term liabilities | 25,218 | 25,135 | ||||||
Total liabilities | 3,466,517 | 3,872,158 | ||||||
Equity | ||||||||
Series A preferred units, 8.0 million units issued and outstanding at December 31, 2015 and December 31, 2014 | 193,215 | 193,215 | ||||||
Series B preferred units, 48.8 million and 0 units issued and outstanding at December 31, 2015 and December 31, 2014, respectively | 353,471 | — | ||||||
Common units, 213.5 million and 210.9 million units issued and outstanding at December 31, 2015 and December 31, 2014, respectively | 852,114 | 3,566,468 | ||||||
Accumulated other comprehensive loss | (229 | ) | (392 | ) | ||||
Total partners' equity | 1,398,571 | 3,759,291 | ||||||
Noncontrolling interest | 7,324 | 6,885 | ||||||
Total equity | 1,405,895 | 3,766,176 | ||||||
Total liabilities and equity | $ | 4,872,412 | $ | 7,638,334 |
Three Months Ended | Year Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
Thousands of dollars, except per unit amounts | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Revenues and other income items | ||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 139,688 | $ | 197,067 | $ | 645,272 | $ | 855,820 | ||||||||
Gain on commodity derivative instruments, net | 141,842 | 587,590 | 438,614 | 566,533 | ||||||||||||
Other revenue, net | 5,934 | 3,376 | 24,829 | 7,616 | ||||||||||||
Total revenues and other income items | 287,464 | 788,033 | 1,108,715 | 1,429,969 | ||||||||||||
Operating costs and expenses | ||||||||||||||||
Operating costs | 106,239 | 107,520 | 455,189 | 355,681 | ||||||||||||
Depletion, depreciation and amortization | 123,312 | 87,292 | 460,047 | 291,709 | ||||||||||||
Impairment of oil and natural gas properties | 878,335 | 119,566 | 2,377,615 | 149,000 | ||||||||||||
Impairment of goodwill | — | — | 95,947 | — | ||||||||||||
General and administrative expenses | 20,599 | 33,063 | 98,999 | 86,949 | ||||||||||||
Restructuring costs | (49 | ) | — | 6,364 | — | |||||||||||
(Gain) loss on sale of assets | (1,542 | ) | 306 | (8,864 | ) | 663 | ||||||||||
Total operating costs and expenses | 1,126,894 | 347,747 | 3,485,297 | 884,002 | ||||||||||||
Operating (loss) income | (839,430 | ) | 440,286 | (2,376,582 | ) | 545,967 | ||||||||||
Interest expense, net of capitalized interest | 51,039 | 36,600 | 203,027 | 126,960 | ||||||||||||
Gain on interest rate swaps | (720 | ) | (490 | ) | 2,691 | (490 | ) | |||||||||
Other income, net | (235 | ) | (523 | ) | (814 | ) | (1,746 | ) | ||||||||
Total other expense | 50,084 | 35,587 | 204,904 | 124,724 | ||||||||||||
(Loss) income before taxes | (889,514 | ) | 404,699 | (2,581,486 | ) | 421,243 | ||||||||||
Income tax expense (benefit) | 1,162 | (457 | ) | 1,527 | (73 | ) | ||||||||||
Net (loss) income | (890,676 | ) | 405,156 | (2,583,013 | ) | 421,316 | ||||||||||
Less: Net income (loss) attributable to noncontrolling interest | 202 | (17 | ) | 326 | (17 | ) | ||||||||||
Net (loss) income attributable to the partnership | (890,878 | ) | 405,173 | (2,583,339 | ) | 421,333 | ||||||||||
Less: Distributions to Series A preferred unitholders | 4,125 | 4,125 | 16,500 | 10,083 | ||||||||||||
Less: Non-cash distributions to Series B preferred unitholders | 7,264 | — | 20,817 | — | ||||||||||||
Less: Net income (loss) attributable to participating units | — | 3,927 | — | 5,348 | ||||||||||||
Less: Distributions on participating units in excess of earnings | — | — | 1,731 | — | ||||||||||||
Net (loss) income used to calculate basic and diluted net (loss) income per unit | $ | (902,267 | ) | $ | 397,121 | $ | (2,622,387 | ) | $ | 405,902 | ||||||
Basic net (loss) income per unit | $ | (4.25 | ) | $ | 2.28 | $ | (12.39 | ) | $ | 3.04 | ||||||
Diluted net (loss) income per unit | $ | (4.25 | ) | $ | 2.27 | $ | (12.39 | ) | $ | 3.02 |
Year Ended December 31, | ||||||||
Thousands of dollars, except per unit amounts | 2015 | 2014 | ||||||
Net (loss) income | $ | (2,583,013 | ) | $ | 421,316 | |||
Other comprehensive (loss) income, net of tax: | ||||||||
Change in fair value of available-for-sale securities (a) | (402 | ) | (189 | ) | ||||
Pension and post-retirement benefit actuarial gain (loss) (b) | 677 | (473 | ) | |||||
Total other comprehensive income (loss), net of tax | 275 | (662 | ) | |||||
Total comprehensive (loss) income | (2,582,738 | ) | 420,654 | |||||
Less: Comprehensive income (loss) attributable to noncontrolling interest | 438 | (287 | ) | |||||
Comprehensive (loss) income attributable to the partnership | $ | (2,583,176 | ) | $ | 420,941 |
Year Ended December 31, | ||||||||
Thousands of dollars | 2015 | 2014 | ||||||
Cash flows from operating activities | ||||||||
Net (loss) income | $ | (2,583,013 | ) | $ | 421,316 | |||
Adjustments to reconcile net (loss) income to cash flow from operating activities: | ||||||||
Depletion, depreciation and amortization | 460,047 | 291,709 | ||||||
Impairment of oil and natural gas properties | 2,377,615 | 149,000 | ||||||
Impairment of goodwill | 95,947 | — | ||||||
Unit-based compensation expense | 26,805 | 23,387 | ||||||
Gain on derivative instruments | (435,923 | ) | (567,024 | ) | ||||
Derivative instrument settlement receipts | 494,234 | 26,806 | ||||||
Income from equity affiliates, net | (104 | ) | 178 | |||||
Deferred income taxes | 1,269 | (174 | ) | |||||
(Gain) loss on sale of assets | (8,864 | ) | 663 | |||||
Other | 16,142 | 6,204 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable and other assets | 35,367 | 41,754 | ||||||
Inventory | 2,801 | 163 | ||||||
Net change in related party receivables and payables | 188 | 142 | ||||||
Accounts payable and other liabilities | (45,806 | ) | (36,369 | ) | ||||
Net cash provided by operating activities | 436,705 | 357,755 | ||||||
Cash flows from investing activities | ||||||||
Property acquisitions | (18,201 | ) | (401,465 | ) | ||||
Capital expenditures | (269,350 | ) | (417,755 | ) | ||||
Other | (853 | ) | (18,283 | ) | ||||
Proceeds from sale of assets | 14,547 | 499 | ||||||
Proceeds from sale of available-for-sale securities | 3,875 | — | ||||||
Purchases of available-for-sale securities | (4,021 | ) | — | |||||
Net cash used in investing activities | (274,003 | ) | (837,004 | ) | ||||
Cash flows from financing activities | ||||||||
Proceeds from issuance of preferred units, net | 337,238 | 193,215 | ||||||
Proceeds from issuance of common units, net | 3,008 | 277,613 | ||||||
Distributions to preferred unitholders | (16,502 | ) | (9,350 | ) | ||||
Distributions to common unitholders | (126,188 | ) | (264,585 | ) | ||||
Proceeds from issuance of long-term debt, net | 1,378,338 | 2,457,600 | ||||||
Repayments of long-term debt | (1,711,500 | ) | (1,785,000 | ) | ||||
Senior note redemption | — | (352,531 | ) | |||||
Change in book overdraft | 11 | (2,434 | ) | |||||
Debt issuance costs | (29,271 | ) | (25,109 | ) | ||||
Net cash (used in) provided by financing activities | (164,866 | ) | 489,419 | |||||
(Decrease) increase in cash | (2,164 | ) | 10,170 | |||||
Cash beginning of period | 12,628 | 2,458 | ||||||
Cash end of period | $ | 10,464 | $ | 12,628 |