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MEMP > SEC Filings for MEMP > Form 10-Q on 10-May-2013All Recent SEC Filings

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Form 10-Q for MEMORIAL PRODUCTION PARTNERS LP


10-May-2013

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS.

Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the unaudited condensed financial statements and accompanying notes in "Item 1. Financial Statements" contained herein and our Annual Report on Form 10-K for the year ended December 31, 2012 (the "2012 Form 10-K"). The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Note Regarding Forward-Looking Statements" in the front of this report.

Overview

We are a Delaware limited partnership formed in April 2011 by Memorial Resource to own, acquire and exploit oil and natural gas properties in North America. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership's operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. After giving effect to the WHT acquisition retrospectively, as of December 31, 2012:

Our total estimated proved reserves were approximately 771 Bcfe, of which approximately 63% were natural gas and 60% were classified as proved developed reserves;

We produced from 1,671 gross (926 net) producing wells across our properties, with an average working interest of 55%, and we or Memorial Resource operated 97% of the properties in which we have interests; and

Our average net production for the three months ended December 31, 2012 was 92.9 MMcfe/d, implying a reserve-to-production ratio of approximately 23 years.

Significant Current Developments

Private Offering of Senior Notes

On April 17, 2013, we and our wholly-owned subsidiary, Finance Corp., (collectively, the "Issuers"), completed a private placement of $300.0 million aggregate principal amount of 7.625% senior unsecured notes due 2021 (the "Senior Notes"). The Senior Notes were issued at 98.521% of par and are guaranteed by all of the Partnership's subsidiaries (other than Finance Corp., which is co-issuer of the Senior Notes, and San Pedro Bay Pipeline Company, which is an immaterial majority-owned subsidiary) jointly and severally on a senior unsecured basis. The Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year, commencing November 1, 2013. For additional information regarding our Senior Notes, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

Amendment to Revolving Credit Facility

On March 19, 2013, we entered into a fifth amendment to our credit agreement, which among other things, increased the borrowing base to $580.0 million upon closing of the acquisition of oil and gas properties from operating subsidiaries of Memorial Resource (discussed below) and extended the maturity date of the credit agreement to March 19, 2018. The borrowing base was reduced to $505.0 million upon issuance of the Senior Notes discussed above. The next borrowing base redetermination is scheduled for October 2013; however, we have the right to seek an interim redetermination if the need arises.


Table of Contents

Acquisition of Oil & Gas Properties

On March 28, 2013, we acquired all of the outstanding equity interests in WHT Energy Partners LLC ("WHT"), which owns certain oil and natural gas properties and related assets in East Texas and North Louisiana (the "WHT properties"), from operating subsidiaries of Memorial Resource for a purchase price of $200.0 million, which included $4.0 million of working capital and other customary adjustments. This acquisition was funded with borrowings under our revolving credit facility and the net proceeds from our March 25, 2013 public offering of common units (including our general partner's proportionate capital contribution). The effective date for this transaction was January 1, 2013. Terms of the transaction were approved by our general partner's board of directors and by its conflicts committee, which is comprised entirely of independent directors. The WHT properties consist of additional working interests in properties that we originally acquired in December 2011 in conjunction with our initial public offering. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method.

Public Equity Offering

On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership (including 1,275,000 common units purchased pursuant to the full exercise of the underwriters' option to purchase additional common units) to the public at an offering price of $18.35 per unit generating total net proceeds of approximately $172.0 million after deducting underwriting discounts and offering expenses.

Business Environment and Operational Focus

Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production, including the effect of our derivative contracts; (iii) lease operating expenses; (iv) general and administrative expenses; and (v) Adjusted EBITDA (defined below).

Production Volumes

Production volumes directly impact our results of operations. Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. We attempt to overcome this natural decline through a combination of acquisitions and development projects and improving the economics of producing oil and natural gas from our properties. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors, including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

Realized Prices on the Sale of our Production

We market our natural gas, NGL and oil production to a variety of purchasers based on regional pricing. The relative prices of natural gas, NGL and oil are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets. We expect commodity prices to be volatile in the future. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for any oil, natural gas or NGLs that we produce will generally approximate market prices in the geographic region of the production.

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point in time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we intend to individually identify these non-speculative hedges as "designated hedges" for U.S. federal income tax purposes as we enter into them, resulting in ordinary income treatment of our realized hedge activity. By removing a significant portion of this price volatility on our future production through December 2018, we have mitigated, but not eliminated, the potential effects of changing commodity prices on our cash flows from operations for those periods.


Table of Contents

Lease Operating Expenses

We strive to increase our production levels to maximize our revenue and cash available for distribution. Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. We monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we monitor our production expenses and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold.

General & Administrative Expenses

We and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner's and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. During the year ended December 31, 2012, Memorial Resource allocated its general and administrative costs based on the relative size of our proved and probable reserves in comparison to Memorial Resource's proved and probable reserves. In January 2013, Memorial Resource began to allocate its general and administrative costs based on our relative production in comparison to Memorial Resource's production, which it believes will more accurately reflect the cost incurred to provide services to us. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf.

Adjusted EBITDA

We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash flow from operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):

Plus:

Interest expense, including realized and unrealized losses on interest rate derivative contracts;

Income tax expense;

Depreciation, depletion and amortization ("DD&A");

Impairment of goodwill and long-lived assets (including oil and natural gas properties) ("Impairment");

Accretion of asset retirement obligations ("AROs");

Unrealized losses on commodity derivative contracts;

Losses on sale of assets and other, net;

Unit-based compensation expenses;

Exploration costs;

Acquisition related costs;

Amortization of investment premium;

Net operating cash flow from acquisitions, effective date through closing date; and

Other non-routine items that we deem appropriate.

Less:

Interest income;

Income tax benefit;

Unrealized gains on commodity derivative contracts;

Gains on sale of assets and other, net; and

Other non-routine items that we deem appropriate.


Table of Contents

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, research analysts and rating agencies, to assess:

our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis;

the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units; and

the viability of projects and the overall rates of return on alternative investment opportunities.

In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

The following tables present our calculation of Adjusted EBITDA as well as a reconciliation of Adjusted EBITDA to cash flows from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.

                                                                 For the Three Months
                                                                    Ended March 31,
                                                                2013               2012
Calculation of Adjusted EBITDA:
Net income (loss)                                            $   (6,245)        $   31,206
Interest expense, net                                              5,033             2,509
Income tax expense                                                    --               183
DD&A                                                              13,155            11,130
Accretion of AROs                                                    998               943
Unrealized (gains) losses on commodity derivative
instruments                                                       16,356          (14,532)
Acquisition related costs                                            215               113
Unit-based compensation expense                                      422               248
Exploration costs                                                     95                --
Amortization of investment premium                                    --               121

Adjusted EBITDA                                              $    30,029        $   31,921


                                                                 For the Three Months
                                                                    Ended March 31,
                                                                2013               2012
Reconciliation of Net Cash from Operating Activities to
Adjusted EBITDA:
Net cash provided by operating activities                    $    28,145        $   31,722
Changes in working capital                                       (1,880)           (1,797)
Interest expense, net                                              5,033             2,509
Unrealized gain (loss) on interest rate swaps                        538             (349)
Acquisition related costs                                            215               113
Amortization of deferred financing fees                          (2,022)             (277)

Adjusted EBITDA                                              $    30,029        $   31,921


Table of Contents

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2012 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis.

When used in the preparation of our consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

Results of Operations

The results of operations for the three months ended March 31, 2013 and 2012 have been derived from both our consolidated financial statements and the previous owners' combined financial statements. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates, the consolidated financial statements of REO from February 3, 2009 (inception) through the date of acquisition, and the consolidated financial statements of WHT from April 8, 2011 through March 28, 2013. The results of operations attributable to the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods. The following table summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.


Table of Contents
                                                               For the Three Months
                                                                 Ended March 31,
                                                             2013               2012
Revenues:
Oil & natural gas sales                                   $   44,035         $    43,289
Pipeline tariff income                                           305                 334
Other income                                                      --                 110

Total revenues                                            $   44,340         $    43,733


Costs and expenses:
Lease operating                                               13,098              13,085
Pipeline operating                                               470                 734
Exploration                                                       95                  --
Production and ad valorem taxes                                2,287               2,481
Depreciation, depletion, and amortization                     13,155              11,130
General and administrative                                     4,787               4,376
Accretion of asset retirement obligations                        998                 943
Realized (gain) loss on commodity derivative
instruments                                                  (5,694)             (8,628)
Unrealized (gain) loss on commodity derivative
instruments                                                   16,356            (14,532)
Other, net                                                        --                 125

Total costs and expenses                                      45,552               9,714
Operating income (loss)                                      (1,212)              34,019
Other income (expense):
Interest expense, net                                        (5,033)             (2,509)
Amortization of investment premium                                --               (121)

Total other income (expense)                                 (5,033)             (2,630)

Income before income taxes                                   (6,245)              31,389
Income tax benefit (expense)                                      --               (183)

Net income (loss)                                            (6,245)              31,206
Net income (loss) attributable to previous owners            (1,219)              10,403
Net income (loss) attributable to noncontrolling
interest                                                         (4)                (91)

Net income attributable to partners                       $  (5,022)         $    20,894


Oil and natural gas revenue:
Oil sales                                                 $   18,424         $    21,121
NGL sales                                                      8,857               6,699
Natural gas sales                                             16,754              15,469

Total oil and natural gas revenue                         $   44,035         $    43,289


Production volumes:
Oil (MBbls)                                                      176                 195
NGLs (MBbls)                                                     270                 129
Natural gas (MMcf)                                             5,686               5,555

Total (MMcfe)                                                  8,363               7,500

Average net production (MMcfe/d)                                92.9                82.4


Average sales price (excluding commodity
derivatives):
Oil (per Bbl)                                             $   104.94         $    108.17
NGL (per Bbl)                                             $    32.74         $     51.98
Natural gas (per Mcf)                                     $     2.95         $      2.78

Total (Mcfe)                                              $     5.27         $      5.77


Average unit costs per Mcfe:
Lease operating expense                                   $     1.57         $      1.74
Production and ad valorem taxes                           $     0.27         $      0.33
General and administrative expenses                       $     0.57         $      0.58
Depletion, depreciation, and amortization                 $     1.57         $      1.48


Table of Contents

Three Months Ended March 31, 2013 Compared to the Three Months Ended March 31, 2012

A net loss of $6.2 million was generated for the three months ended March 31, 2013, of which $1.2 million was attributable to the previous owners. Net income was $31.2 million for the three months ended March 31, 2012, of which $10.4 million was attributable to the previous owners. The decrease in net income was largely attributable to an unrealized loss on commodity derivatives of $16.4 million that was recognized during 2013 compared to an unrealized gain on commodity derivatives of $14.5 million that was recognized during 2012.

Revenues. Oil, natural gas and NGL revenues for 2013 totaled $44.0 million, an increase of $0.7 million compared with 2012. Production increased 863 MMcfe (approximately 12%) and the average realized sales price (excluding realized gain on derivatives) decreased $0.50 per Mcfe. The favorable volume variance contributed to an approximate $5.0 million increase in revenues, which was partially offset by the unfavorable pricing variance.

In January 2013, the Partnership temporarily shut-in production from one of its offshore Southern California production platforms for 26 days to allow for maintenance and inspection services on segments of the associated platform piping systems. The production impact of the shut-in was approximately 72 MBbls gross (28 MBbls net).

Effective January 1, 2013, we also began presenting NGLs volumes and revenues produced from our South Texas properties separately from gas volumes and revenues for accounting purposes. This change in presentation had no impact on total oil and natural gas revenue reported for the comparable period.

Lease Operating. Lease operating expenses for both 2013 and 2012 were $13.1 million. Lease operating expenses associated with third party acquisitions that were consummated during 2012 was approximately $0.8 million. Excluding results from these third party acquisitions, lease operating expense decreased by $0.8 million primarily due to less workover expenses and operational efficiencies. On a per Mcfe basis, lease operating expenses decreased to $1.57 for 2013 from $1.74 for 2012.

Production and Ad Valorem Taxes. Production and ad valorem taxes for 2013 totaled $2.3 million, a decrease of $0.2 million compared with 2012. On a per Mcfe basis, production and ad valorem taxes decreased to $0.27 for 2013 from $0.33 for 2012.

Depreciation, Depletion and Amortization. DD&A expense for 2013 was $13.2 million compared to $11.1 million for 2012, a $2.1 million period-to-period increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions consummated during 2012. DD&A expense per Mcfe was $1.57 for 2013 compared to $1.48 for 2012. Increased production volumes caused DD&A expense to increase by an approximate $1.3 million and the 6% change in the DD&A rate between periods caused DD&A expense to increase by an approximate $0.8 million.

General and Administrative. General and administrative expenses include the costs of administrative employees and related benefits, management fees paid to affiliates, professional fees and other costs not directly associated with field operations. General and administrative expenses for 2013 were $4.8 million, of which $0.6 million was attributable to the previous owners. General and administrative expenses for 2013 included $0.4 million of non-cash unit-based compensation expense and $0.2 million of acquisition-related costs. General and administrative expenses for 2012 totaled $4.4 million, of which $2.4 million was attributable to the previous owners.

On a per Mcfe basis, general and administrative expenses were $0.57 in 2013 compared to $0.58 in 2012 due to increased production volumes.

Gain/Loss on Derivative Instruments. Net losses on commodity derivative instruments of $10.7 million were recognized during 2013, of which $5.7 million were realized gains and $16.4 million were unrealized losses. Net gains on commodity derivative instruments of $23.2 million were recognized during 2012, of which $8.6 million were realized gains and $14.5 million were unrealized gains.

Given the volatility of commodity prices, it is not possible to predict future reported unrealized mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be . . .

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