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24.07.2013 15:00:00
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PVR Partners Announces Second Quarter 2013 Results and Declares Cash Distribution
RADNOR, Pa., July 24, 2013 /PRNewswire/ -- PVR Partners, L.P. (NYSE: PVR) ("PVR") today reported financial and operational results for the three months ended June 30, 2013. In addition, PVR declared a quarterly distribution of $0.55 per unit.
(Logo: http://photos.prnewswire.com/prnh/20110224/PH54022LOGO )
Second Quarter Results
Second quarter 2013 highlights and results, with comparisons to results for the second quarter of 2012 ("last year") and the first quarter of 2013 ("last quarter"), included the following:
- Adjusted EBITDA of $76.1 million as compared to $57.0 million last year and $76.0 million last quarter.
- Distributable Cash Flow ("DCF") of $49.0 million as compared to $32.9 million last year and $49.9 million last quarter.
- Average daily natural gas throughput volumes of 1.7 billion cubic feet per day ("Bcfd") as compared with 0.9 Bcfd last year and 1.6 Bcfd last quarter.
Adjusted EBITDA and DCF are not Generally Accepted Accounting Principles ("GAAP") measures. Definitions and reconciliations of these non-GAAP measures to GAAP reporting measures appear in the financial tables which follow.
Quarterly Distribution
The Board of Directors of PVR GP, LLC, the general partner of PVR, declared a quarterly distribution of $0.55 per unit payable in cash on August 14, 2013 to common unitholders of record at the close of business on August 7, 2013. This distribution equates to an annualized rate of $2.20 per unit, which is unchanged from the distribution paid with respect to the first quarter of 2013 and represents a 3.8% increase over the distribution paid with respect to the second quarter of 2012.
Management Comment
"Our second quarter results were consistent with our first quarter performance, and significantly ahead of last year's second quarter results," said Bill Shea, President and CEO of PVR's general partner. "However, results for the second quarter were below our expectations primarily due to producers delaying well connections in our Eastern Midstream operations. Some wells originally scheduled for connection in the second quarter have been delayed until later this year resulting in lower second quarter throughput volumes. These delays have negatively impacted our 2013 revenue projections and we have adjusted our 2013 guidance to reflect the financial impact on our full year results.
"Our continued belief in the long-term prospects for our Eastern Midstream operations is supported by strong results from the wells that have been drilled and completed within our areas of operations, the continuing level of drilling activity within the region, and the overall scope and scale of the future drilling plans communicated by producers," continued Mr. Shea. "However, changes in producers' detailed schedules can materially impact volume and revenue growth on a quarter to quarter basis. Based on the revised well connection schedules most recently provided by producers, we expect total average daily Eastern Midstream throughput volumes at year end will be in the range of 1.6 to 1.8 Bcfd."
Eastern Midstream Segment Results
The Eastern Midstream Segment reported second quarter 2013 results, with comparisons to second quarter 2012 results and the first quarter of 2013, as follows:
- Adjusted EBITDA of $38.1 million as compared to $17.7 million last year and $37.7 million last quarter, primarily due to the continued development of internal growth projects and the acquisition of Chief Gathering LLC.
- Quarterly average throughput volumes of 1.3 Bcfd as compared to 0.5 Bcfd last year and 1.2 Bcfd last quarter, reflecting growth on PVR's existing systems, as well as the acquisition and expansion of the Chief Gathering systems.
Midcontinent Midstream Segment Results
The Midcontinent Midstream Segment reported second quarter 2013 results, with comparisons to second quarter 2012 results and the first quarter of 2013, as follows:
- Adjusted EBITDA of $14.9 million as compared to $12.7 million last year and $15.7 million last quarter.
- Quarterly average throughput volumes of 382 MMcfd as compared to 453 MMcfd last year and 391 MMcfd last quarter. Second quarter 2012 volumes included approximately 52 MMcfd attributable to the Crossroads system that was sold on July 3, 2012.
Coal and Natural Resource Management Segment Results
The Coal and Natural Resource Management Segment reported second quarter 2013 results, with comparisons to second quarter 2012 results and the first quarter of 2013, as follows:
- Adjusted EBITDA of $23.1 million as compared to $26.7 million last year and $22.7 million last quarter. The year-over-year decline was primarily due to decreased coal production and pricing.
- Coal royalty tons of 6.9 million tons as compared to 7.8 million tons last year and 6.4 million tons last quarter.
- Coal royalties revenue of $23.2 million, or $3.37 per ton, as compared to $29.2 million, or $3.76 per ton last year and $23.0 million or $3.56 per ton last quarter.
Second quarter 2013 coal segment revenue included a $2.3 million one-time recognition of forfeitures of minimum payments from a lessee declaring bankruptcy.
Capital Investment and Resources
We invested $110.9 million on internal growth projects in our midstream businesses during the second quarter of 2013, of which $97.5 million was invested in the Eastern Midstream Segment.
On May 9th, PVR closed a $400 million offering of Senior Notes. The net proceeds from the offering were used to repay a portion of the borrowings outstanding under PVR's $1.0 billion revolving credit facility. As of June 30, 2013, we had borrowings of $457.5 million under our revolving credit facility, with remaining borrowing capacity thereunder of $532.1 million after adjusting for outstanding letters of credit.
Expansion Projects Update
The development and build-out of important growth projects in the Marcellus, Utica, Cline and Mississippian Lime continued during the second quarter of 2013.
- Construction of the new "Severcool" compressor facility and central delivery point on the Wyoming County trunkline was completed and began operation during June. Completion of these facilities added 85 MMcfd of firm volume commitment to the Wyoming trunkline beginning July 1, 2013.
- The new interconnection into the Wyoming trunkline for Carrizo Oil & Gas and Reliance Group began service during June.
- The second phase of the new Lycoming gathering system, for which Inflection Energy is the primary shipper, was completed and began service in the second quarter. Work on additional phases of this system continues.
- Completion of 13 new well connections in the Eastern Midstream Segment during the second quarter.
- Construction of the initial phase of our gathering system in Greene County, Pennsylvania has been completed. Volume on the system during the second quarter averaged 12 MMcfd.
- Early phase development work continues on a proposed new trunkline and gathering system in the Utica shale.
- Completion of 52 new well connections in the Midcontinent Midstream Segment during the second quarter.
Financial Guidance for 2013
Based on current expectations, management has updated its Adjusted EBITDA guidance for 2013. Full year 2013 Adjusted EBITDA for the Eastern Midstream Segment is now expected to be in the range of $160 to $185 million and the Midcontinent Midstream Segment is now expected to be in the range of $60 to $70 million. Adjusted EBITDA for the Coal and Natural Resource Management Segment in the range of $75 to $85 million remains unchanged. Management now anticipates that full year 2013 maintenance capital expenditures will be in the range of $13 to $15 million. PVR's expectation for full year 2013 internal growth capital in the range of $350 to $400 million remains unchanged.
PVR's financial guidance is based on numerous assumptions about future events and conditions and, therefore, could vary materially from actual results. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision for acquisitions or operating environment changes. Adjusted EBITDA is a non-GAAP measure; reconciliations of non-GAAP measures to GAAP reporting measures appear in the financial tables which follow.
Second Quarter 2013 Financial and Operational Results Conference Call
A conference call and webcast, during which management will discuss second quarter 2013 financial and operational results, is scheduled for Wednesday, July 24, 2013 at 2:00 p.m. Eastern Daylight Time. Prepared remarks by members of company management will be followed by a question and answer period. Interested parties may listen via webcast at http://www.videonewswire.com/event.asp?id=94745 or by logging on using the link posted on our website, www.pvrpartners.com. Participants who would like to ask questions may join the conference via phone by dialing 800-860-2442 (international 412-858-4600) five to ten minutes before the scheduled start of the conference call (reference the PVR Partners call). An on-demand replay of the webcast will be available on our website shortly after the conclusion of the call. A telephonic replay of the call will be available through July 31 by dialing 877-344-7529 (international: 412-317-0088) and using conference playback number 10030534.
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PVR Partners, L.P. (NYSE: PVR) is a publicly traded limited partnership which owns and operates a network of natural gas midstream pipelines and processing plants, and owns and manages coal and natural resource properties. Our midstream assets, located principally in Texas, Oklahoma and Pennsylvania, provide gathering, transportation, compression, processing, dehydration and related services to natural gas producers. Our coal and natural resource properties, located in the Appalachian, Illinois and San Juan basins, are leased to experienced operators in exchange for royalty payments. More information about PVR is available on our website at www.pvrpartners.com.
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This release is intended to be a qualified notice under Treasury Regulation Section 1.1446-4(b). Brokers and nominees should treat one hundred percent (100.0%) of the Partnership's distributions to non-U.S. investors as being attributable to income that is effectively connected with a United States trade or business. Accordingly, the Partnership's distributions to non-U.S. investors are subject to federal income tax withholding at the highest applicable effective tax rate.
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This press release includes "forward-looking statements" within the meaning of federal securities laws. All statements, other than statements of historical facts, included in this 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. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Partnership's ability to control or predict, which could cause results to differ materially from those expected by management. Such risks and uncertainties include, but are not limited to, regulatory, economic and market conditions, our ability realize the anticipated benefits from the acquisition of Chief Gathering LLC, the timing and success of business development efforts and other uncertainties. Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2012 and most recently filed Quarterly Reports on Form 10-Q. Readers should not place undue reliance on forward-looking statements, which reflect management's views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.
Contact: | Stephen R. Milbourne |
Director - Investor Relations | |
Phone: 610-975-8204 | |
E-Mail: invest@pvrpartners.com |
PVR PARTNERS, L.P. | ||||||||
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - unaudited | ||||||||
(in thousands, except per unit data) | ||||||||
Three Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
2013 | 2012 | 2013 | 2012 | |||||
Revenues | ||||||||
Natural gas | $ 103,111 | $ 63,127 | $ 190,825 | $ 137,754 | ||||
Natural gas liquids | 93,470 | 102,130 | 193,978 | 219,924 | ||||
Gathering fees | 25,886 | 11,149 | 48,802 | 18,612 | ||||
Trunkline fees | 21,653 | 10,255 | 42,754 | 16,647 | ||||
Coal royalties | 23,223 | 29,231 | 46,174 | 62,390 | ||||
Other | 6,122 | 7,020 | 14,343 | 14,002 | ||||
Total revenues | 273,465 | 222,912 | 536,876 | 469,329 | ||||
Expenses | ||||||||
Cost of gas purchased | 167,074 | 140,833 | 325,282 | 306,297 | ||||
Operating | 17,150 | 14,040 | 32,520 | 29,943 | ||||
General and administrative | 13,172 | 10,999 | 26,957 | 23,043 | ||||
Acquisition related costs | - | 14,049 | - | 14,049 | ||||
Impairments | - | - | - | 124,845 | ||||
Depreciation, depletion and amortization | 46,113 | 28,456 | 90,899 | 52,309 | ||||
Total expenses | 243,509 | 208,377 | 475,658 | 550,486 | ||||
Operating income (loss) | 29,956 | 14,535 | 61,218 | (81,157) | ||||
Other income (expense) | ||||||||
Interest expense | (26,326) | (15,511) | (50,004) | (25,328) | ||||
Derivatives | 846 | 8,676 | 405 | 3,725 | ||||
Interest income and other | 1,032 | 109 | 1,126 | 225 | ||||
Net income (loss) | $ 5,508 | $ 7,809 | $ 12,745 | $ (102,535) | ||||
Earnings (loss) per common unit, basic and diluted | $ (0.21) | $ (0.07) | $ (0.38) | $ (1.39) | ||||
Weighted average number of common units outstanding, basic and diluted | 95,947 | 83,786 | 95,927 | 81,543 | ||||
Weighted average number of Class B units outstanding | 23,136 | 10,572 | 22,879 | 5,286 | ||||
Weighted average number of Special units outstanding | 10,346 | 5,116 | 10,346 | 2,558 | ||||
Other data by segment: | ||||||||
Eastern Midstream: | ||||||||
Gathered volumes (MMcfd) | 612 | 336 | 598 | 273 | ||||
Trunkline volumes (MMcfd) (1) | 698 | 120 | 671 | 106 | ||||
Midcontinent Midstream: | ||||||||
Daily throughput volumes (MMcfd) | 382 | 453 | 387 | 448 | ||||
Coal and Natural Resource Management: | ||||||||
Coal royalty tons (in thousands) | 6,893 | 7,776 | 13,339 | 15,881 | ||||
(1) Trunkline volumes include a significant portion of gathered volumes. | ||||||||
PVR PARTNERS, L.P. | ||||||||
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited | ||||||||
(in thousands) | ||||||||
June 30, | December 31, | |||||||
2013 | 2012 | |||||||
Assets | ||||||||
Cash and cash equivalents | $ 13,923 | $ 14,713 | ||||||
Accounts receivable | 132,669 | 133,546 | ||||||
Assets held for sale | - | 11,450 | ||||||
Derivative assets | 425 | - | ||||||
Other current assets | 5,368 | 5,446 | ||||||
Total current assets | 152,385 | 165,155 | ||||||
Property, plant and equipment, net | 2,124,764 | 1,989,346 | ||||||
Other long-term assets | 840,661 | 844,208 | ||||||
Total assets | $ 3,117,810 | $ 2,998,709 | ||||||
Liabilities and Partners' Capital | ||||||||
Accounts payable and accrued liabilities | $ 144,551 | $ 197,034 | ||||||
Deferred income | 4,548 | 3,788 | ||||||
Derivative liabilities | 46 | - | ||||||
Total current liabilities | 149,145 | 200,822 | ||||||
Other long-term liabilities | 30,400 | 35,468 | ||||||
Senior notes | 1,300,000 | 900,000 | ||||||
Revolving credit facility | 457,500 | 590,000 | ||||||
Partners' capital | 1,180,765 | 1,272,419 | ||||||
Total liabilities and partners' capital | $ 3,117,810 | $ 2,998,709 | ||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited | ||||||||
(in thousands) | ||||||||
Three Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
2013 | 2012 | 2013 | 2012 | |||||
Cash flows from operating activities | ||||||||
Net income (loss) | $ 5,508 | $ 7,809 | $ 12,745 | $ (102,535) | ||||
Adjustments to reconcile net income (loss) to | ||||||||
net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 46,113 | 28,456 | 90,899 | 52,309 | ||||
Impairments | - | - | - | 124,845 | ||||
Commodity derivative contracts: | ||||||||
Total derivative gains included in net income | (846) | (8,676) | (405) | (3,725) | ||||
Cash receipts (payments) to settle derivatives for the period | 32 | (3,605) | (190) | (7,246) | ||||
Non-cash interest expense | 1,830 | 1,579 | 3,482 | 2,628 | ||||
Non-cash unit-based compensation | 844 | 1,519 | 2,108 | 3,557 | ||||
Equity earnings, net of distributions received | 2,349 | 186 | 3,674 | (555) | ||||
Other | (1,064) | (51) | (3,068) | (698) | ||||
Changes in operating assets and liabilities | (29,159) | (3,742) | (4,223) | 62 | ||||
Net cash provided by operating activities | 25,607 | 23,475 | 105,022 | 68,642 | ||||
Cash flows from investing activities | ||||||||
Acquisitions | 12 | (850,747) | (2,334) | (850,943) | ||||
Additions to property, plant and equipment | (120,903) | (99,621) | (259,349) | (174,994) | ||||
Joint venture capital contributions | - | (5,100) | (10,200) | (11,700) | ||||
Proceeds from sale of assets | - | - | 11,964 | - | ||||
Other | 290 | 330 | 1,872 | 640 | ||||
Net cash used in investing activities | (120,601) | (955,138) | (258,047) | (1,036,997) | ||||
Cash flows from financing activities | ||||||||
Distributions to partners | (52,786) | (41,265) | (105,521) | (81,683) | ||||
Net proceeds from equity offering | - | 577,962 | - | 577,962 | ||||
Proceeds from issuance of senior notes | 400,000 | 600,000 | 400,000 | 600,000 | ||||
Proceeds from borrowings, net | (242,500) | (185,000) | (132,500) | (109,000) | ||||
Cash paid for debt issuance costs | (8,658) | (18,589) | (9,537) | (18,589) | ||||
Other | (112) | - | (207) | - | ||||
Net cash provided by financing activities | 95,944 | 933,108 | 152,235 | 968,690 | ||||
Net increase (decrease) in cash and cash equivalents | 950 | 1,445 | (790) | 335 | ||||
Cash and cash equivalents - beginning of period | 12,973 | 7,530 | 14,713 | 8,640 | ||||
Cash and cash equivalents - end of period | $ 13,923 | $ 8,975 | $ 13,923 | $ 8,975 | ||||
PVR PARTNERS, L.P. | |||||||||||||
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited | |||||||||||||
(in thousands) | |||||||||||||
Three Months Ended | Six Months Ended | Guidance Range | |||||||||||
June 30, | June 30, | Full Year 2013 | |||||||||||
2013 | 2012 | 2013 | 2012 | Low | High | ||||||||
Reconciliation of Non-GAAP "Total Segment Adjusted EBITDA" to GAAP "Net income (loss)": | |||||||||||||
Segment Adjusted EBITDA (a): | |||||||||||||
Eastern Midstream | $ 38,090 | $ 17,659 | $ 75,781 | $ 27,620 | $ 160,000 | $ 185,000 | |||||||
Midcontinent Midstream | 14,926 | 12,684 | 30,630 | 25,007 | 60,000 | 70,000 | |||||||
Coal and Natural Resource Management | 23,053 | 26,697 | 45,706 | 57,419 | 75,000 | 85,000 | |||||||
Total segment adjusted EBITDA | $ 76,069 | $ 57,040 | $ 152,117 | $ 110,046 | $ 295,000 | $ 340,000 | |||||||
Adjustments to reconcile total Segment Adjusted EBITDA to Net income (loss) | |||||||||||||
Depreciation, depletion and amortization | (46,113) | (28,456) | (90,899) | (52,309) | (180,000) | (190,000) | |||||||
Impairments on PP&E | - | - | - | (124,845) | - | - | |||||||
Acquisition related costs | - | (14,049) | - | (14,049) | - | - | |||||||
Interest expense | (26,326) | (15,511) | (50,004) | (25,328) | (95,000) | (100,000) | |||||||
Derivatives | 846 | 8,676 | 405 | 3,725 | - | - | |||||||
Other | 1,032 | 109 | 1,126 | 225 | - | - | |||||||
Net income (loss) | $ 5,508 | $ 7,809 | $ 12,745 | $ (102,535) | $ 20,000 | $ 50,000 | |||||||
Reconciliation of GAAP "Net income (loss)" to Non-GAAP "Distributable cash flow": | |||||||||||||
Net income (loss) | $ 5,508 | $ 7,809 | $ 12,745 | $ (102,535) | |||||||||
Depreciation, depletion and amortization | 46,113 | 28,456 | 90,899 | 52,309 | |||||||||
Impairments on PP&E | - | - | - | 124,845 | |||||||||
Acquisition related costs | - | 14,049 | - | 14,049 | |||||||||
Derivative contracts: | |||||||||||||
Derivative gains included in net income | (846) | (8,676) | (405) | (3,725) | |||||||||
Cash receipts (payments) to settle derivatives for the period | 32 | (3,605) | (190) | (7,246) | |||||||||
Equity earnings from joint ventures, net of distributions | 2,349 | 186 | 3,674 | (555) | |||||||||
Maintenance capital expenditures | (4,150) | (5,351) | (7,814) | (8,448) | |||||||||
Distributable cash flow (b) | $ 49,006 | $ 32,868 | $ 98,909 | $ 68,694 | |||||||||
Distribution to Partners: | |||||||||||||
Total cash distribution paid during the period | $ 52,786 | $ 41,265 | $ 105,521 | $ 81,683 | |||||||||
Reconciliation of GAAP "Net income (loss)" to Non-GAAP "Net income as adjusted": | |||||||||||||
Net income (loss) | $ 5,508 | $ 7,809 | $ 12,745 | $ (102,535) | |||||||||
Impairments on PP&E and equity investments | - | - | - | 124,845 | |||||||||
Acquisition related costs | - | 14,049 | - | 14,049 | |||||||||
Adjustments for derivatives: | |||||||||||||
Derivative gains included in net income | (846) | (8,676) | (405) | (3,725) | |||||||||
Cash receipts (payments) to settle derivatives for the period | 32 | (3,605) | (190) | (7,246) | |||||||||
Net income, as adjusted (c) | $ 4,694 | $ 9,577 | $ 12,150 | $ 25,388 | |||||||||
(a) Segment Adjusted EBITDA, or earnings before interest, tax and depreciation, depletion and amortization ("DD&A"), represents net income plus DD&A, plus impairments, plus acquisition related costs, plus interest expense, minus derivative gains and other items included in net income. We believe EBITDA or a version of Adjusted EBITDA is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the natural gas midstream and coal industries. We use this information for comparative purposes within the industry. Adjusted EBITDA is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.
(b) Distributable cash flow represents net income plus DD&A, plus impairments, plus acquisition related costs, plus (minus) derivative losses (gains) included in net income, plus (minus) cash received (paid) for derivative settlements, minus equity earnings in joint ventures, plus cash distributions from joint ventures, minus maintenance capital expenditures. At management's discretion, a fixed amount of $1.8 million per quarter in 2013 and $1.3 million per quarter in 2012 has been included in maintenance capital for well connects. Distributable cash flow is also the quantitative standard used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of publicly traded partnerships. Distributable cash flow is presented because we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities, as an indicator of cash flows, as a measure of liquidity or as an alternative to net income. For comparative purposes, prior year amounts exclude replacement capital expenditures.
(c) Net income, as adjusted, represents net income adjusted to exclude the effects of non-cash impairment charges, one-time charges related to acquisitions and changes in the fair value of derivatives. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the natural gas midstream industry. We use this information for comparative purposes within the industry. Net income, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income. | |||||||||||||
PVR PARTNERS, L.P. | ||||||||
QUARTERLY SEGMENT INFORMATION - unaudited | ||||||||
(in thousands) | ||||||||
Eastern Midstream | ||||||||
Three Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
2013 | 2012 | 2013 | 2012 | |||||
Revenues | ||||||||
Gathering fees | $ 25,003 | $ 9,385 | $ 47,141 | $ 14,304 | ||||
Trunkline fees | 21,653 | 10,255 | 42,754 | 16,647 | ||||
Other | (1,218) | 1,484 | (560) | 1,646 | ||||
Total revenues | 45,438 | 21,124 | 89,335 | 32,597 | ||||
Expenses | ||||||||
Operating | 2,875 | 1,189 | 4,855 | 2,087 | ||||
General and administrative | 4,473 | 2,276 | 8,699 | 2,890 | ||||
Acquisition related costs | - | 14,049 | - | 14,049 | ||||
Depreciation, depletion and amortization | 23,462 | 8,394 | 46,106 | 10,455 | ||||
Total expenses | 30,810 | 25,908 | 59,660 | 29,481 | ||||
Operating income (loss) | $ 14,628 | $ (4,784) | $ 29,675 | $ 3,116 | ||||
Midcontinent Midstream | ||||||||
Three Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
2013 | 2012 | 2013 | 2012 | |||||
Revenues | ||||||||
Natural gas | $ 103,111 | $ 63,127 | $ 190,825 | $ 137,754 | ||||
Natural gas liquids | 93,470 | 102,130 | 193,978 | 219,924 | ||||
Gathering fees | 883 | 1,764 | 1,661 | 4,308 | ||||
Other | 403 | 928 | 1,546 | 1,545 | ||||
Total revenues | 197,867 | 167,949 | 388,010 | 363,531 | ||||
Expenses | ||||||||
Cost of gas purchased | 167,074 | 140,833 | 325,282 | 306,297 | ||||
Operating | 10,574 | 9,251 | 20,928 | 20,478 | ||||
General and administrative | 5,293 | 5,181 | 11,170 | 11,749 | ||||
Impairments | - | - | - | 124,845 | ||||
Depreciation, depletion and amortization | 15,054 | 11,700 | 29,960 | 25,307 | ||||
Total expenses | 197,995 | 166,965 | 387,340 | 488,676 | ||||
Operating income (loss) | $ (128) | $ 984 | $ 670 | $ (125,145) | ||||
Coal and Natural Resource Management | ||||||||
Three Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
2013 | 2012 | 2013 | 2012 | |||||
Revenues | ||||||||
Coal royalties | $ 23,223 | $ 29,231 | $ 46,174 | $ 62,390 | ||||
Coal services | 848 | 1,391 | 2,009 | 2,630 | ||||
Timber | 1,686 | 1,354 | 3,118 | 2,873 | ||||
Oil and gas royalties | 692 | 505 | 1,347 | 1,188 | ||||
Other | 3,711 | 1,358 | 6,883 | 4,120 | ||||
Total revenues | 30,160 | 33,839 | 59,531 | 73,201 | ||||
Expenses | ||||||||
Operating | 3,701 | 3,600 | 6,737 | 7,378 | ||||
General and administrative | 3,406 | 3,542 | 7,088 | 8,404 | ||||
Depreciation, depletion and amortization | 7,597 | 8,362 | 14,833 | 16,547 | ||||
Total expenses | 14,704 | 15,504 | 28,658 | 32,329 | ||||
Operating income | $ 15,456 | $ 18,335 | $ 30,873 | $ 40,872 | ||||
PVR PARTNERS, L.P. | |||||
DERIVATIVE CONTRACT SUMMARY - unaudited | |||||
As of June 30, 2013 | |||||
Average Volume Per Day | |||||
Swap | |||||
Price | |||||
Crude oil swap (WTI) | (barrels) | (per barrel) | |||
Third quarter through the fourth quarter 2013 | 500 | $94.80 | |||
Natural gas swaps (1) | (MMBtu) | (per MMBtu) | |||
Third quarter through the fourth quarter 2013 | 5,500 | $3.823 | |||
Our exposure profile with respect to commodity prices depends on many factors, including inlet volumes, plant operational efficiencies, contractual terms, and the price relationship between ethane and natural gas.
We anticipate operating our plants in "ethane rejection" for the remainder of 2013. Under this operational mode, we estimate that for every $1.00 per MMBtu change in the natural gas price, our natural gas midstream gross margin and operating income for the remainder of 2013 would change by $7.8 million, excluding the effect of the natural gas hedges described above, and all other factors remaining constant. The natural gas hedges described above would reduce the net impact to $6.8 million.
Similarly, for every $5.00 per barrel change in crude oil prices, with all other factors remaining constant, and excluding the effect of the 2013 crude oil derivative described above, we estimate that our natural gas midstream gross margin and operating income would change by $1.4 million. The crude oil hedge described above would reduce the net impact to $0.9 million.
For every $0.10 per gallon increase in the price of ethane with all other factors remaining constant, we estimate that our gross margin and operating income will decrease by $1.6 million while operating in ethane rejection. Finally, for every $0.10 per gallon increase in the price of other NGLs with all other factors remaining constant, we estimate that our gross margin and operating income will increase by $1.3 million.
(1) The natural gas swaps settle against the monthly index price reported in Inside FERC's Natural Gas Market Report for Southern Star Central Gas Pipeline (Texas, Oklahoma, Kansas), which has historically tended to be settled at a lower price than the Henry Hub national benchmark. A significant portion of our physical gas sales are also priced using this reported monthly index.
PVR PARTNERS, L.P. | |||||
OPERATING STATISTICS | |||||
($ Amounts in 000s) | |||||
Three Months Ended | Six Months Ended | ||||
June 30, | June 30, | ||||
2013 | 2012 | 2013 | 2012 | ||
EASTERN MIDSTREAM | |||||
Volumes (MMcfd) | |||||
Lycoming Trunkline | 340 | 120 | 338 | 106 | |
Wyoming Trunkline | 358 | - | 333 | - | |
Total Trunkline Volume | 698 | 120 | 671 | 106 | |
Lycoming Gathering | 238 | 138 | 230 | 115 | |
Wyoming Gathering | 189 | 145 | 190 | 132 | |
East Lycoming Gathering | 122 | 44 | 120 | 22 | |
Bradford Gathering | 52 | 7 | 50 | 4 | |
Greene Gathering | 12 | 2 | 8 | 1 | |
Total Gathering | 612 | 336 | 598 | 273 | |
Total Throughput | 1,310 | 456 | 1,269 | 379 | |
Total Trunkline Fees | $ 21,653 | $ 10,255 | $ 42,754 | $ 16,647 | |
Total Gathering Fees | $ 25,003 | $ 9,385 | $ 47,141 | $ 14,304 | |
Trunkline Fees / Mcf | $ 0.34 | $ 0.94 | $ 0.35 | $ 0.86 | |
Gathering Fees / Mcf | $ 0.45 | $ 0.31 | $ 0.44 | $ 0.29 | |
MIDCONTINENT MIDSTREAM | |||||
Volumes (MMcfd) | |||||
Panhandle System | 328 | 351 | 334 | 343 | |
Crossroads System (1) | - | 52 | - | 55 | |
Crescent System | 31 | 24 | 29 | 23 | |
Hamlin System | 6 | 7 | 6 | 7 | |
Total Processing Systems | 365 | 434 | 369 | 428 | |
Arkoma System | 9 | 9 | 9 | 10 | |
North Texas System | 8 | 9 | 8 | 10 | |
Total Gathering Only Systems | 17 | 19 | 18 | 20 | |
Total All Systems | 382 | 453 | 387 | 448 | |
Total Gathering and Processing Fees, Net(2) | $ 30,390 | $ 26,188 | $ 61,182 | $ 55,689 | |
Fees Per Mcf | $ 0.87 | $ 0.64 | $ 0.87 | $ 0.68 | |
(1) Crossroads System was sold July 3, 2012 | |||||
(2) Processing fees include revenues from natural gas, natural gas liquids and gathering fees less cost of gas purchased | |||||
COAL PRODUCTION | |||||
Coal royalty tons by region (000s) | |||||
Central Appalachia | 2,784 | 3,476 | 5,401 | 7,544 | |
Northern Appalachia | 1,231 | 1,100 | 2,007 | 1,898 | |
Illinois Basin | 658 | 962 | 1,329 | 2,099 | |
San Juan Basin | 2,220 | 2,238 | 4,602 | 4,340 | |
Total Tons | 6,893 | 7,776 | 13,339 | 15,881 | |
Total Coal Royalties | $ 23,223 | $ 29,231 | $ 46,174 | $ 62,390 | |
Average Coal Royalty per ton | $ 3.37 | $ 3.76 | $ 3.46 | $ 3.93 | |
SOURCE PVR Partners, L.P.
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