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PVR > SEC Filings for PVR > Form 10-K on 28-Feb-2014All Recent SEC Filings

Show all filings for PVR PARTNERS, L. P.

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


28-Feb-2014

Annual Report


Item 7 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," "we," "us" or "our") should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8. 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 currently conduct operations in three business segments which are as follows:

Eastern Midstream - Our Eastern Midstream segment is engaged in providing natural gas gathering, transportation and other related services in Pennsylvania, Ohio and West Virginia. In addition, we own membership 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. 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.

Our operating income (loss) was $132.7 million in 2013, compared to $(4.6) million in 2012 and $153.6 million in 2011. In 2013, our Eastern Midstream segment contributed $68.5 million to our operating income, our Midcontinent Midstream segment contributed $12.2 million, and our Coal and Natural Resource Management segment contributed $52.0 million to operating income.

Eastern Midstream Segment Overview

As of December 31, 2013, we owned and operated natural gas midstream assets located in Pennsylvania and West Virginia including approximately 257 miles of natural gas gathering pipelines, 68 miles of natural gas trunkline pipelines and 42 miles of fresh water pipelines. Our Eastern Midstream segment earns revenues primarily from fees charged to producers for natural gas gathering, compression and other related services. During 2013, we continued construction of our internal growth projects and acquired assets in the Chief acquisition.

In 2013, average gathered volumes on our systems were approximately 649 MMcfd, while our average trunkline volumes were approximately 742 MMcfd. These average flow rates have increased from 2012 average gathered volumes of 389 MMcfd and average trunkline volumes of 197 MMcfd. A significant volume of gas flows through both gathering and trunkline systems. The annual increase in volumes is attributed to the completion of internal growth projects.

We continually seek new supplies of natural gas both to offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors' systems. In 2013, our Eastern Midstream natural gas segment made aggregate capital expenditures of $288.4 million, primarily related to the construction of internal growth projects and acquired assets in the Chief Acquisition, expanding our footprint in the Marcellus Shale.

Midcontinent Midstream Segment Overview

As of December 31, 2013, we owned and operated natural gas midstream assets located in Oklahoma and Texas including six natural gas processing facilities having 460 MMcfd of total capacity and approximately 4,650 miles of natural gas gathering pipelines. Our Midcontinent Midstream natural gas business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services.


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System throughput volumes at our gas processing plants and gathering systems, including gathering only volumes, were approximately 379 MMcfd in 2013, compared to 432 MMcfd in 2012. The decrease in throughput volumes is attributed to the sale of the Crossroads Plant in 2012 and declines in natural gas production.

We continually seek new supplies of natural gas both to offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors' systems. In 2013, Midcontinent Midstream natural gas segment made aggregate capital expenditures of $66.7 million, primarily related to our expansion of the Panhandle and Crescent systems due to growth opportunities in those areas.

Coal and Natural Resource Segment Overview

As of December 31, 2013, we owned or controlled approximately 847 million tons of proven and probable coal reserves in Central and Northern Appalachia, the Illinois Basin and the San Juan Basin. We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In 2013, our lessees produced 25.1 million tons of coal from our properties and paid us coal royalties revenues of $88.1 million, for an average royalty per ton of $3.50. Approximately 65% of our coal royalties revenues in 2013 was derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of our coal royalties revenues for the respective periods was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually. For the year ended December 31, 2013, $22.1 million in coal royalties were earned in the San Juan Basin. During 2014, our coal reserves located in the San Juan Basin will deplete and the associated royalty revenue will cease.

Coal royalties are impacted by several factors that we generally cannot control. The number of tons mined annually is determined by an operator's mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. Legislation or regulations have been or may be adopted which may have a significant impact on the mining operations of our lessees or their customers' ability to use coal and which may require us, our lessees or our lessees' customers to change operations significantly or incur substantial costs. See Item 1A, "Risk Factors."

To a lesser extent, coal prices also impact coal royalties revenues. Generally, as coal prices change over time, our average royalty per ton may change as the majority of our lessees pay royalties based on the gross sales prices of the coal mined. However, most of our lessees' coal is sold under contracts with a duration of one year or more; therefore, the underlying prices for our royalties are less susceptible to short-term volatility in coal prices and prices change primarily as our lessees' long-term contracts are renegotiated.

We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees.

Key Developments

Proposed Merger

On October 9, 2013, we entered into an Agreement and Plan of Merger with Regency Energy Partners LP (or "Regency"), RVP LLC, a Delaware limited liability company and Regency's wholly owned subsidiary, and Regency's general partner. Pursuant to the Agreement and Plan of Merger, as amended by Amendment No. 1 thereto dated as of November 7, 2013 (or the "Regency Merger Agreement"), we will merge with and into Regency (or the "Regency Merger"), and Regency will continue its existence under Delaware law as the surviving entity in the Regency Merger. Regency has filed with the Securities Exchange Commission ("SEC") a registration statement on Form S-4 (or the "Form S-4") relating to the merger.

The Regency Merger Agreement provides that, at the effective time of the merger, each of our common units and each of our class B units issued and outstanding or deemed issued and outstanding as of immediately prior to the effective time will be converted into the right to receive the merger consideration, consisting of
(i) 1.020 of Regency common units and (ii) an amount of cash equal to the difference between (x) our annualized distribution less (y) Regency's adjusted annualized distribution. Our annualized distribution is the product of four and the per unit amount of the quarterly cash distribution most recently declared by us prior to the closing of the Regency Merger. Regency's adjusted annualized distribution is the product of four and the per unit amount of quarterly cash distribution most recently declared by Regency prior to the closing of the Regency Merger, multiplied by the exchange ratio of 1.020.

The completion of the Regency Merger is subject to the satisfaction or waiver of certain customary closing conditions, including, among other things:
(i) approval of the Regency Merger Agreement by our unitholders, (ii) approval for listing of Regency common units issuable as part of the merger consideration on the New York Stock Exchange, (iii) there being no law or injunction


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prohibiting the consummation of the Regency Merger, (iv) the effectiveness of the Form S-4, (v) subject to specified materiality standards, the accuracy of the representations and warranties of each party, (vi) compliance by each party in all material respects with its covenants and (vii) the receipt of certain legal opinions by us and Regency.

If the Regency Merger Agreement is not adopted by PVR unitholders or if the Regency Merger is not completed for any other reason, PVR unitholders will not receive any form of consideration for their PVR units in connection with the merger. Instead, PVR will remain an independent publicly traded limited partnership and its common units will continue to be listed and traded on the NYSE. If the Regency Merger Agreement is terminated under specified circumstances, including if unitholder approval is not obtained, PVR will be required to pay all of the reasonably documented out-of-pocket expenses incurred by Regency and its affiliates in connection with the Regency Merger Agreement and the transactions contemplated thereby, up to a maximum amount of $20.0 million. In addition, if the Regency Merger Agreement is terminated in specified circumstances, including due to an adverse recommendation change having occurred, PVR will be required to pay Regency a termination fee of $134.5 million, less any expenses previously paid by PVR to Regency. Following payment of the termination fee, PVR will not be obligated to pay any additional expenses incurred by Regency or its affiliates.

Eastern Midstream Segment

In September 2013, we announced that we entered into a definitive agreement to construct, own and operate a 45-mile natural gas trunkline and associated gathering pipelines and facilities servicing lean gas production in the Utica Shale in eastern Ohio. We expect the aggregate capital investment for the trunkline, initial gathering line, compression stations and dehydration facilities to be $125.0 million to $150.0 million through 2015.

Midcontinent Midstream Segment

On August 19, 2013, we sold our 25% membership interest in Thunder Creek Gas Services LLC, a joint venture that gathers and transports coalbed methane gas in Wyoming's Powder River Basin. This Midcontinent Midstream investment was accounted for using the equity method of accounting, and had a carrying value of $44.3 million. The proceeds from the sale were $58.6 million, resulting in a gain of $14.3 million recorded in other revenues on the Consolidated Statement of Operations.

2013 Commodity Prices

With the exception of NGLs processed at Mont Belvieu, Texas, the average commodity prices for natural gas, NGLs, condensate and crude oil increased in 2013 from levels experienced in 2012. 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. This volatility is somewhat mitigated by the growing fee-based business in the Eastern Midstream segment. We continually monitor commodity prices and when it appears opportunistic, we may choose to use derivative financial instruments to hedge NGLs sold and natural gas purchased. As of December 31, 2013, we had no open derivative positions hedging commodity prices.

Coal royalties, which accounted for 80% of the Coal and Natural Resource Management segment revenues for the year ended December 31, 2013, were lower compared to 2012. During 2013, weaker international and domestic economies, weak demand for electricity, low natural gas prices and coal to gas switching by utilities have reduced the demand for coal, a trend which is expected to continue into 2014.

PVR Equity Issuance

In September and October of 2013, we issued a total of 6.1 million common units, including the over allotment exercise by the underwriter, representing limited partner interests in PVR in a registered public offering (the "Equity Issuance"). Total net proceeds of approximately $138.0 million, after deducting estimated fees and expenses and underwriting discounts and commissions totaling approximately $2.2 million, were initially used to repay a portion of the Revolver.

Unsecured Partial Debt Redemption

On December 1, 2013, using a portion of the proceeds received from the Equity Issuance, we redeemed $127.4 million of our 8.375% Senior Notes. Pursuant to the terms of the indenture, we paid the note holders 108.375% of the principal amount plus accrued and unpaid interest up to the redemption date. As a result of this redemption, we incurred a charge of $13.7 million related to the call premium and the write-off of unamortized debt issuance costs. The charge was recorded in loss on extinguishment of debt in continuing operations of the Consolidated Statement of Operations. The remaining balance of the 8.375% Senior Notes is $472.6 million.


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At The Market ("ATM") Equity Program

An ATM program is an alternative way of raising capital by issuing equity through existing markets over a period of time. The flexibility of timing the issuance of units helps us to match demand for capital with the supply by controlling the number of units issued. Additionally, it reduces the volatility of unit price by avoiding issuance of a large number of common units at one time. In August 2013 we issued our prospectus supplement relating to the issuance and sale from time to time of common units representing limited partner interests in PVR, or common units, having an aggregate offering price of up to $150.0 million through one or more sales agents. These sales, if any, will be made pursuant to the terms of the ATM equity offering sales agreement between us and the sales agents. The compensation of sales agents for the sales of common units shall not exceed 2.0% of the gross sales price per common unit. The net proceeds from any sales under this ATM program will be used for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of December 31, 3013, no sales have been made under the ATM program.

Special Units

In connection with the closing of the Chief Acquisition, on May 17, 2012, we issued 10,346,257 Special Units (the "Special Units") to Chief E&D Holdings LP. The Special Units were a new class of PVR limited partner interests with a fair value of $191.3 million and were substantially similar to our common units, except that the Special Units neither paid nor accrued distributions for six consecutive quarters commencing after the closing of the Chief Acquisition. The Special Units automatically converted into common units on a one-for-one basis on the first business day after the record date for distributions with respect to the quarter ended September 30, 2013, which was November 7, 2013.

6.5% Senior Notes

In May 2013, we sold $400.0 million of senior notes due on May 15, 2021 in a private placement with an annual interest rate of 6.5% ("6.5% Senior Notes"), which is payable semi-annually in arrears on May 15 and November 15 of each year beginning on November 15, 2013. The 6.5% Senior Notes were sold at par, equating to an effective yield to maturity of approximately 6.5%. The net proceeds from the sale of the 6.5% Senior Notes of approximately $391.0 million, after deducting fees and expenses of approximately $9.0 million, were used to repay borrowings under the Revolver. They are fully and unconditionally guaranteed by our existing and future domestic subsidiaries, subject to certain exceptions. The 6.5% Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness including the Revolver to the extent of the collateral securing that indebtedness.

Results of Operations

Consolidated Review

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



                                                           Year Ended December 31,
                                                 2013               2012               2011
Revenues                                      $ 1,117,486       $  1,007,754       $  1,159,975
Expenses                                         (984,803 )       (1,012,351 )       (1,006,404 )

Operating income (loss)                           132,683             (4,597 )          153,571
Other income (expense)                           (119,689 )          (66,025 )          (57,228 )

Net income (loss)                                  12,994            (70,622 )           96,343
Net loss (income) attributable to
noncontrolling interests, pre-PVR-PVG
merger                                                 -                  -                 664

Net income (loss) attributable to PVR
Partners, L.P.                                $    12,994       $    (70,622 )     $     97,007

Eastern Midstream Segment

Year Ended December 31, 2013 Compared With Year Ended December 31, 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:


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                                                                                                    % Change
                                        Year Ended December 31,             Favorable               Favorable
                                         2013               2012          (Unfavorable)           (Unfavorable)
Financial Highlights
Revenues
Gathering fees                       $    102,161         $ 46,975       $        55,186                      117 %
Trunkline fees                             98,847           47,002                51,845                      110 %
Other                                        (791 )          5,373                (6,164 )                   (115 %)

Total revenues                            200,217           99,350               100,867                      102 %


Expenses
Operating                                  11,173            7,332                (3,841 )                    (52 %)
General and administrative                 19,817            9,854                (9,963 )                   (101 %)
Merger and acquisition costs                2,713           14,049                11,336                       81 %
Depreciation and amortization              97,973           42,713               (55,260 )                   (129 %)

Total operating expenses                  131,676           73,948               (57,728 )                    (78 %)


Operating income                     $     68,541         $ 25,402       $        43,139                      170 %


Operating Statistics
Gathered volumes (MMcfd)                      649              389                   260                       67 %
Trunkline volumes (MMcfd) (1)                 742              197                   545                      277 %

(1) Trunkline volumes include a significant portion of gathered volumes.

Revenues

Gathering and trunkline fees have increased due to the significant increase in volumes. The volume growth and related revenue growth reflects the completion of construction and the expansion of business on our Lycoming and Wyoming systems, as well as the acquired Chief assets.

Other revenue primarily represented operations from our investment in a joint venture. During 2013, our joint venture earnings decreased due to lower water deliveries compared to prior year, and construction management fees decreased due to lower levels of construction on the water pipeline.

Expenses

Consistent with the increase in revenues, operating expenses for the segment increased primarily due to the completion of expansion projects and the related costs to operate the assets. Costs include employees and related benefits, chemicals and lubricants to operate the gathering pipelines and trunklines.

General and administrative expenses increased due to the addition of management, including increased employee costs and related benefits, and corporate overhead allocation. Other administrative costs such as legal and office space rentals have also increased.

Merger and acquisition costs in 2013 relate to the announced Regency Merger, and include costs related to finder's fees, advisory, legal, accounting, valuation and other professional and consulting fees. Similar to corporate overhead, these costs are allocated equally across all segments. The 2012 costs relate to one-time expenses of the Chief Acquisition, which included investment banking, legal and due diligence fees and expenses.

Depreciation and amortization expenses increased primarily due to completion of construction on internal growth projects.


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Year Ended December 31, 2012 Compared With Year Ended December 31, 2011

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
                                        Year Ended December 31,             Favorable              Favorable
                                         2012              2011           (Unfavorable)          (Unfavorable)
Financial Highlights
Revenues
Gathering fees                       $     46,975        $   8,716       $        38,259                    439 %
Trunkline fees                             47,002           17,454                29,548                    169 %
Other                                       5,373               -                  5,373                    N/A

Total revenues                             99,350           26,170                73,180                    280 %


Expenses
Operating                                   7,332            1,499                (5,833 )                 (389 %)
General and administrative                  9,854            1,238                (8,616 )                 (696 %)
Merger and acquisition costs               14,049               -                (14,049 )                  N/A
Depreciation and amortization              42,713            4,243               (38,470 )                 (907 %)

Total operating expenses                   73,948            6,980               (66,968 )                 (959 %)


Operating income                     $     25,402        $  19,190       $         6,212                     32 %


Operating Statistics
Gathered volumes (MMcfd)                      389               74                   315                    426 %
Trunkline volumes (MMcfd) (1)                 197               40                   157                    393 %

(1) Trunkline volumes include a significant portion of gathered volumes.

Revenues

Gathering and trunkline fees have increased due to the significant increase in volumes. The volume growth and related revenue growth reflects the expansion of business on our existing Lycoming and Wyoming systems, as well as the acquisition of Chief Gathering LLC. In February 2011, we commenced operations on the first phase of the Lycoming County system. In April 2011, we also began construction on the second phase of the Lycoming County system, a portion of which became operational in the fourth quarter of 2011. In April of 2012, we began construction on the third phase of the Lycoming County system, which became operational by the end of the year. The Lycoming County system consists of 53 miles of 30- inch trunkline. In May of 2012, we completed the acquisition of Chief Gathering LLC, adding 120 miles of gathering pipelines, 350 MMcfd of capacity and over 300,000 dedicated acres in the Marcellus Shale to the Eastern Midstream segment. In the fourth quarter of 2012, we commenced operation of Wyoming Pipeline, which consists of 30 miles of 24-inch diameter natural gas trunkline.

Other revenue primarily represented operations from our investment in a joint venture. In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale region. The initial 12 mile section of the water line became operational in March 2012 and water line expansion in conjunction with construction of Phase III of our Lycoming system. In addition, we receive a fee for managing certain projects of the joint venture and an accounting services fee. The fees recognized in revenues were after intercompany eliminations.

Expenses

Consistent with the increase in revenues, operating expenses for the segment increased primarily due to expansion projects and the Chief Acquisition.

General and administrative expenses increased due to the addition of management and operational personnel in our Williamsport, Pennsylvania office, increased equity compensation and corporate overhead. We added the Eastern Midstream segment in the second quarter of 2012 due to the Chief Acquisition and our expansion activities in Pennsylvania. As a result of the acquisition and . . .

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