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PVR > SEC Filings for PVR > Form 10-Q on 29-Jul-2013All Recent SEC Filings

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Form 10-Q for PVR PARTNERS, L. P.


29-Jul-2013

Quarterly Report


Item 2 Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations of PVR Partners, L.P. and its subsidiaries (the "Partnership," "PVR," "we," "us" or "our") should be read in conjunction with our Consolidated Financial Statements and Notes thereto in Item 1. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated.

Overview of Business

We are a publicly traded Delaware limited partnership that is principally engaged in the gathering, transportation and processing of natural gas and the management of coal and natural resource properties in the United States.

We manage our business in three operating segments: (i) Eastern Midstream,
(ii) Midcontinent Midstream and (iii) Coal and Natural Resource Management.

Eastern Midstream - Our Eastern Midstream segment is engaged in providing natural gas gathering, transportation and other related services in Pennsylvania and West Virginia. In addition, we own member interests in a joint venture that transports fresh water to natural gas producers.

Midcontinent Midstream - Our Midcontinent Midstream segment is engaged in providing natural gas gathering, processing and other related services. In addition, we own member interests in a joint venture that gathers and transports natural gas. These processing and gathering systems are located primarily in Oklahoma and Texas.

Coal and Natural Resource Management - Our Coal and Natural Resource Management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities and collecting oil and gas royalties.

Key Developments

During the six months ended June 30, 2013, the following general business developments and corporate actions had an impact, or will have an impact, on our results of operations. A discussion of these key developments follows:

Eastern Midstream

Construction continues on the acquired assets and existing systems. We invested approximately $170.2 million in the first six months of 2013 constructing gathering systems, trunklines and compressor stations. As a result of the construction and our producers adding well connects, our average system volumes (including both gathering and trunkline volumes) increased from 967 MMcfd in the fourth quarter of 2012 to 1,310 MMcfd in the second quarter of 2013.

Midcontinent Midstream

Construction efforts were primarily concentrated in the Panhandle and Crescent systems. We invested approximately $30.8 million in the first six months of 2013 constructing gathering systems and compressor stations. Our average system volumes decreased from 448 MMcfd in the first half of 2012 to 387 MMcfd in the first half of 2013 primarily due to the sale of the Crossroads plant at the beginning of July 2012. The Crossroads plant processed approximately 55 MMcfd in the first half of 2012. Also contributing to the decrease were natural production declines and weather-related shut-ins of wells, partially offset by increases related to recently completed construction and our producers adding well connects.


Table of Contents

2013 Commodity Prices

Revenues, profitability and the future rate of growth of our Midcontinent Midstream segment is highly dependent on market demand and prevailing NGL and natural gas prices. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas. As a result, we may use derivative financial instruments to hedge commodity prices. Our current derivative financial instruments include swaps for crude oil (to hedge condensate volumes) and natural gas. We currently have three commodity derivatives, all of which expire at the end of 2013.

Results of Operations

Consolidated Review

The following table presents summary consolidated results for the periods
presented:



                                  Three Months Ended               Six Months Ended
                                       June 30,                        June 30,
                                 2013            2012            2013            2012
    Revenues                  $  273,465      $  222,912      $  536,876      $  469,329
    Expenses                    (243,509 )      (208,377 )      (475,658 )      (550,486 )

    Operating income (loss)       29,956          14,535          61,218         (81,157 )
    Other income (expense)       (24,448 )        (6,726 )       (48,473 )       (21,378 )

    Net income (loss)         $    5,508      $    7,809          12,745        (102,535 )

Eastern Midstream Segment

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 2012

The following table sets forth a summary of certain financial and other data for
our Eastern Midstream segment and the percentage change for the periods
presented:



                                                                                                          % Change
                                        Three Months Ended June 30,                Favorable              Favorable
                                        2013                   2012              (Unfavorable)          (Unfavorable)
Financial Highlights
Revenues
Gathering fees                      $      25,003          $       9,385        $        15,618                    166 %
Trunkline fees                             21,653                 10,255                 11,398                    111 %
Other                                      (1,218 )                1,484                 (2,702 )                 (182 %)

Total revenues                             45,438                 21,124                 24,314                    115 %


Expenses
Operating                                   2,875                  1,189                 (1,686 )                 (142 %)
General and administrative                  4,473                  2,276                 (2,197 )                  (97 %)
Acquisition related costs                      -                  14,049                 14,049                    N/A
Depreciation and amortization              23,462                  8,394                (15,068 )                 (180 %)

Total operating expenses                   30,810                 25,908                 (4,902 )                  (19 %)


Operating income (loss)             $      14,628          $      (4,784 )      $        19,412                   (406 %)


Operating Statistics
Gathered volumes (MMcfd)                      612                    336                    276                     82 %
Trunkline volumes (MMcfd)                     698                    120                    578                    482 %

Revenues

Gathering and trunkline fees have increased due to the significant increase in volumes. The development and completion of our expansion projects and the acquisition of Chief Gathering LLC in May 2012 have added significant volumes to the system.

Other revenue primarily represented operations from our investment in a joint venture and related management fees. The decrease in equity earnings from the joint venture relates to decreased volumes transported in the comparable periods. The timing of water flow to various producers relates to the producers' drilling schedules. The related need for water changes over time due to the number of rigs running and timing of such drilling.


Table of Contents

Expenses

Operating expenses increased due to prior and current years' expansion projects and the acquisition of Chief Gathering LLC in May 2012. The related costs of these facilities included increased field salaries, supplies, chemicals, lubricants and environmental costs.

General and administrative expenses increased due to the addition of personnel, increased office space, equity compensation and corporate overhead.

Acquisition costs in 2012 relate to the one-time expenses of the Chief acquisition, which included investment banking, legal and due diligence fees and expenses.

Depreciation and amortization expenses increased as a result of capital expended on acquisitions and internal growth projects.

Eastern Midstream Segment

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 2012

The following table sets forth a summary of certain financial and other data for
our Eastern Midstream segment and the percentage change for the periods
presented:



                                                                                                      % Change
                                        Six Months Ended June 30,              Favorable              Favorable
                                        2013                 2012            (Unfavorable)          (Unfavorable)
Financial Highlights
Revenues
Gathering fees                      $     47,141         $     14,304       $        32,837                    230 %
Trunkline fees                            42,754               16,647                26,107                    157 %
Other                                       (560 )              1,646                (2,206 )                 (134 %)

Total revenues                            89,335               32,597                56,738                    174 %


Expenses
Operating                                  4,855                2,087                (2,768 )                 (133 %)
General and administrative                 8,699                2,890                (5,809 )                 (201 %)
Acquisition related costs                     -                14,049                14,049                    N/A
Depreciation and amortization             46,106               10,455               (35,651 )                 (341 %)

Total operating expenses                  59,660               29,481               (30,179 )                 (102 %)


Operating income                    $     29,675         $      3,116       $        26,559                    852 %


Operating Statistics
Gathered volumes (MMcfd)                     598                  273                   325                    119 %
Trunkline volumes (MMcfd)                    671                  106                   565                    533 %

Revenues

Gathering and trunkline fees have increased due to the significant increase in volumes. The development and completion of our expansion projects and the acquisition of Chief Gathering LLC in May 2012 have added significant volumes to the system.

Other revenue primarily represented operations from our investment in a joint venture and related management fees. The decrease in equity earnings from the joint venture relates to decreased volumes transported in the comparable periods. The timing of water flow to various producers relates to the producers' drilling schedules. The related need for water changes over time due to the number of rigs running and timing of such drilling.

Expenses

Operating expenses increased due to prior and current years' expansion projects and the acquisition of Chief Gathering LLC in May 2012. The related costs of these facilities included increased field salaries, supplies, chemicals, lubricants and environmental costs.

General and administrative expenses increased due to the addition of personnel, increased office space, equity compensation and corporate overhead.


Table of Contents

Acquisition costs in 2012 relate to the one-time expenses of the Chief acquisition, which included investment banking, legal and due diligence fees and expenses.

Depreciation and amortization expenses increased as a result of capital expended on acquisitions and internal growth projects.

Midcontinent Midstream Segment

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 2012

The following table sets forth a summary of certain financial and other data for
our Midcontinent Midstream segment and the percentage change for the periods
presented:



                                                                                                         % Change
                                         Three Months Ended June 30,              Favorable              Favorable
                                         2013                  2012             (Unfavorable)          (Unfavorable)
Financial Highlights
Revenues
Natural gas                          $     103,111         $      63,127       $        39,984                     63 %
Natural gas liquids                         93,470               102,130                (8,660 )                   (8 %)
Gathering fees                                 883                 1,764                  (881 )                  (50 %)
Other                                          403                   928                  (525 )                  (57 %)

Total revenues                             197,867               167,949                29,918                     18 %


Expenses
Cost of gas purchased                      167,074               140,833               (26,241 )                  (19 %)
Operating                                   10,574                 9,251                (1,323 )                  (14 %)
General and administrative                   5,293                 5,181                  (112 )                   (2 %)
Depreciation and amortization               15,054                11,700                (3,354 )                  (29 %)

Total operating expenses                   197,995               166,965               (31,030 )                  (19 %)


Operating income (loss)              $        (128 )       $         984       $        (1,112 )                  113 %


Operating Statistics
Daily throughput volumes (MMcfd)               382                   453                   (71 )                  (16 %)

Revenues

Revenues primarily included residue gas sold from processing plants after natural gas liquids ("NGLs") were removed, NGLs sold after being removed from system throughput volumes received, gathering and transportation fees. The Antelope Hills facility became operational in 2012. This addition to the Panhandle System enables us to meet our current and expected future processing requirements in this area. We are also improving the connectivity between plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the area producers, including those in the Granite Wash.

Natural gas revenues increased primarily due to higher natural gas prices. The average New York Mercantile Exchange (NYMEX) natural gas spot price increased 84%, from $2.22 in the second quarter of 2012 to $4.09 in the comparable period of 2013. We have been in ethane rejection mode during 2013 due to the compressed pricing differentials between ethane and natural gas and retaining ethane in the natural gas stream has been more valuable than extracting it as an NGL. Partially offsetting the increase in higher natural gas prices was a decrease in throughput volumes primarily due to the sale of the Crossroads plant at the beginning of July 2012. The Crossroads plant processed approximately 52 MMcfd in the second quarter of 2012.

NGL and condensate revenues decreased primarily due to being in ethane rejection mode. Offsetting the lack of ethane revenues was a minor increase in our average realized price received for a Conway NGL barrel in the second quarter of 2013, which was $31.51 compared to $29.49 for the same period of 2012. NGL and condensate prices can fluctuate significantly based on market conditions in certain areas. In order to obtain favorable pricing, we sell our NGLs and condensate to several customers in multiple markets.

Gathering and processing fees decreased due to the sale of the Crossroads plant. Gathering and processing fees for Crossroads in the second quarter of 2012 were $0.8 million.

Other revenues included decreased earnings from our natural gas gathering joint venture in Wyoming due to decreased volumes. Also, marketing fees decreased due to a marketing agreement expiring in 2012, and lower producer services fees were assessed in 2013 due to expired agreements.


Table of Contents

Expenses

Cost of gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts. The amounts we pay producers fluctuate each period due to the volumes related to each type of processing contract and plant recoveries. We continue to enter into more fee based contracts to reduce our commodity exposure. Cost of gas purchased increased primarily due to the average NYMEX natural gas spot price increasing by $1.87, or 84%, from $2.22 in the second quarter of 2012 to $4.09 in the same period of 2013. Offsetting the increase was the sale of the Crossroads plant at the beginning of July 2012.

Operating expenses increased primarily due to personnel costs, compressor rentals, chemicals and utility costs. Some of these increased costs relate to the new Antelope Hills facility that became operational during 2012. The increase was offset by the sale of the Crossroads plant at the beginning of July 2012.

Depreciation and amortization expenses increased as a result of capital expended on internal growth projects.

Midcontinent Midstream Segment

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 2012

The following table sets forth a summary of certain financial and other data for
our Midcontinent Midstream segment and the percentage change for the periods
presented:



                                                                                                      % Change
                                        Six Months Ended June 30,              Favorable              Favorable
                                         2013                2012            (Unfavorable)          (Unfavorable)
Financial Highlights
Revenues
Natural gas                          $     190,825        $  137,754        $        53,071                     39 %
Natural gas liquids                        193,978           219,924                (25,946 )                  (12 %)
Gathering fees                               1,661             4,308                 (2,647 )                  (61 %)
Other                                        1,546             1,545                      1                      0 %

Total revenues                             388,010           363,531                 24,479                      7 %


Expenses
Cost of gas purchased                      325,282           306,297                (18,985 )                   (6 %)
Operating                                   20,928            20,478                   (450 )                   (2 %)
General and administrative                  11,170            11,749                    579                      5 %
Impairments                                     -            124,845                124,845                    N/A
Depreciation and amortization               29,960            25,307                 (4,653 )                  (18 %)

Total operating expenses                   387,340           488,676                101,336                     21 %


Operating income (loss)              $         670        $ (125,145 )      $       125,815                   (101 %)


Operating Statistics
Daily throughput volumes (MMcfd)               387               448                    (61 )                  (14 %)

Revenues

Natural gas revenues increased primarily due to higher natural gas prices. The average New York Mercantile Exchange (NYMEX) natural gas spot price increased 50%, from $2.48 in the first half of 2012 to $3.71 in the comparable period of 2013. We have been in ethane rejection mode during the first half of 2013 due to compressed pricing between ethane and natural gas and retaining ethane in the natural gas stream has been more valuable than extracting it as an NGL. Partially offsetting the increase in higher natural gas prices was a decrease in throughput volumes primarily due to the sale of the Crossroads plant at the beginning of July 2012. The Crossroads plant processed approximately 55 MMcfd in the first half of 2012.

NGL and condensate revenues decreased primarily due to the prices received and being in ethane rejection mode. Our average realized price received for a Conway NGL barrel in the first half of 2013 was $34.43 compared to $35.69 for the same period of 2012. NGL and condensate prices can fluctuate significantly based on market conditions in certain areas. In order to obtain favorable pricing, we sell our NGLs and condensate to several customers in multiple markets.


Table of Contents

Gathering and processing fees decreased due to the sale of the Crossroads plant. Gathering and processing fees for Crossroads in the first half of 2012 were $2.2 million.

Other revenues remained relatively constant with offsetting increases and decreases. During the first quarter of 2013, we sold a plant under construction and recorded a gain of $0.5 million. This increase was offset by decreased earnings from a natural gas gathering joint venture in Wyoming due to decreased volumes. Also, marketing fees decreased due to a marketing agreement expiring in 2012, and lower producer services fees were assessed in 2013 due to expired agreements.

Expenses

Cost of gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts. The amounts we pay producers fluctuate each period due to the volumes related to each type of processing contract and plant recoveries. We continue to enter into more fee based contracts to reduce our commodity exposure. Cost of gas purchased increased primarily due to the average NYMEX natural gas spot price increasing by $1.23, or 50%, from $2.48 in the first half of 2012 to $3.71 for the same period of 2013. Offsetting the increase was the sale of the Crossroads plant at the beginning of July 2012.

Operating expenses increased due to the startup operations of the new Antelope Hills facility, which became operational during 2012. This addition to the Panhandle System enables us to meet our current and expected future processing requirements in this area. We are also improving the connectivity between plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the area producers, including those in the Granite Wash. The increase was offset by the sale of the Crossroads plant at the beginning of July 2012.

During the first quarter of 2012, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets located in the southern portion of the Fort Worth Basin of north Texas (the "North Texas Gathering System"). This impairment was triggered by continuing market declines of natural gas prices and lack of drilling in the area.

Depreciation and amortization expenses increased as a result of capital expended on internal growth projects.

Coal and Natural Resource Management Segment

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 2012

The following table sets forth a summary of certain financial and other data for
our Coal and Natural Resource Management segment and the percentage change for
the periods presented:



                                                                                                         % Change
                                        Three Months Ended June 30,               Favorable              Favorable
                                         2013                  2012             (Unfavorable)          (Unfavorable)
Financial Highlights
Revenues
Coal royalties                      $       23,223        $       29,231       $        (6,008 )                  (21 %)
Other                                        6,937                 4,608                 2,329                     51 %

Total revenues                              30,160                33,839                (3,679 )                  (11 %)


Expenses
Operating                                    3,701                 3,600                  (101 )                   (3 %)
General and administrative                   3,406                 3,542                   136                      4 %
Depreciation, depletion and
amortization                                 7,597                 8,362                   765                      9 %

Total expenses                              14,704                15,504                   800                      5 %


Operating income                    $       15,456        $       18,335       $        (2,879 )                  (16 %)


Other data

Coal royalty tons                            6,893                 7,776                  (883 )                  (11 %)

Average coal royalties per ton      $         3.37        $         3.76       $         (0.39 )                  (10 %)


Table of Contents

Revenues

Coal royalties, which accounted for 77% of the Coal and Natural Resource Management segment revenues for the three months ended June 30, 2013 and 86% for the three months ended 2012, were lower in 2013 as compared to 2012. The decrease was a result of less coal being produced by our lessees and lower coal prices. The reduced demand for coal from our lessees' customers was primarily due to domestic electrical generation switching from coal to natural gas and lower metallurgical coal pricing. Coal royalty tonnage decreased because customers cannot utilize all of the coal producers have mined. The surplus due to lower demand has resulted in decreased production and reduced prices.

Other revenues increased due to minimum forfeitures recognized from a lessee declaring bankruptcy. We are actively seeking a new lessee to mine the minerals from the vacated property.

Expenses

Operating expenses increased primarily due to production on subleased properties. Mining activity on our subleased property fluctuates between periods due to the proximity of our property boundaries to other mineral owners.

General and administrative expenses decreased due to lower employee costs.

DD&A expenses decreased for the comparative periods as a result of the decrease in coal production and the related depletion expense.

Coal and Natural Resource Management Segment

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 2012

The following table sets forth a summary of certain financial and other data for
our Coal and Natural Resource Management segment and the percentage change for
the periods presented:



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