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| MEMP > SEC Filings for MEMP > Form 10-Q on 14-Aug-2012 | All Recent SEC Filings |
14-Aug-2012
Quarterly Report
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, 2011 (the "2011 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 publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market ("NASDAQ") under the symbol "MEMP." We were formed in April 2011 by Memorial Resource to own and acquire oil and natural gas properties in North America and completed our initial public offering ("IPO") on December 14, 2011. 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 and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which Memorial Resource performs services for us and our general partner, including the operation of our properties.
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, Columbus and ETX. Our assets consist of oil and natural gas producing properties that are primarily located in South and East Texas/North Louisiana.
We believe our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), will provide us with access to a portfolio of additional oil and natural gas properties that meet our acquisition criteria. The following table summarizes information about Memorial Resource's proved oil and natural gas reserves by geographic region as of June 30, 2012 and average net production for the six months ended June 30, 2012:
Average
Estimated Net Proved Reserves (1) Average Net Production Reserve-to-
% Natural % Proved % of Production
Bcfe Gas Developed MMcfe/d Total Ratio (2)
(Years)
East Texas / North Louisiana 1,183.5 71 % 37 % 104.8 94 % 30.9
Rockies / Midcontinent 51.0 24 % 41 % 6.9 6 % 20.3
Aggregate 1,234.5 69 % 37 % 111.7 100 % 30.3
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(1) The estimates of net proved reserves were prepared by Memorial Resource's internal reserve engineers and are based on various assumptions, including assumptions related to oil and natural gas prices as of June 30, 2012, drilling and operating expenses, capital expenditures, taxes and availability of funds. These internal estimates of net proved reserves may differ materially from estimates of net proved reserves as of December 31, 2012, prepared by independent reserve engineers, as estimates are prepared using SEC pricing (historical twelve month average).
(2) The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of June 30, 2012 by average net production for the six months ended June 30, 2012.
Based on Memorial Resource's intention to develop its properties and significant ownership interests in us, we believe we may be able to acquire additional assets from Memorial Resource, the Funds, or their respective affiliates in the future. None of Memorial Resource, the Funds, or any of their respective affiliates will have any obligation to offer or sell properties to us. See "- Significant Current Developments" below for additional information regarding the Partnership's acquisitions of oil and gas properties from Memorial Resource in April and May 2012.
Significant Current Developments
Acquisition of Oil & Gas Properties - Common Control
On April 2, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $18.5 million, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2013 commodity derivative positions. The transaction was approved by the board of directors of our general partner (the "Board") and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Willow Springs field in Gregg County, as well as in Upshur, Rusk, Panola, Smith and Leon counties in East Texas. Memorial Resource will continue to operate 84% of the acquired properties and the remaining 16% will continue to be operated by third parties. Based on average net daily production of 2.3 MMcfe at the time of acquisition, approximately 82% is natural gas and the remaining 18% is oil and NGLs.
On May 14, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $27.0 million, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2014 commodity derivative positions. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Cotton Valley and Travis Peak fields in Panola and Shelby counties in East Texas. Based on average net daily production of 4.2 MMcfe at the time of acquisition, approximately 81% is natural gas and the remaining 19% is oil and NGLs.
Our acquisitions of oil and gas properties from Memorial Resource in April and May 2012 were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at Memorial Resource's carrying value and our consolidated and predecessor financial statements previously filed with the SEC and presented herein were recast to include the financial position and results attributable to these oil and gas properties for all periods presented on a combined basis. The historical financial position and results attributable to these oil and gas properties were prepared from Memorial Resource's cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. See Note 1 of the unaudited condensed financial statements included in "Item 1. Financial Statements" for more information about the Partnership's basis of presentation.
Acquisition of Oil & Gas Properties - Third Party
On May 1, 2012, we acquired non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller for approximately $37.3 million, subject to customary post-closing adjustments. The effective date of this transaction was January 1, 2012. This transaction was financed with borrowings under our revolving credit facility. Because this transaction was a joint acquisition with Memorial Resource, the transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. Memorial Resource will operate 75% of the acquired properties and the remaining 25% will be operated by third parties. Based on average net daily production of 3.5 MMcfe at the time of acquisition, approximately 61% is natural gas and the remaining 39% is oil and NGLs. This acquisition was accounted for as a business combination using the acquisition method of accounting. See Note 3 of the unaudited condensed financial statements included in "Item 1. Financial Statements" for more information about this acquisition.
Third Independent Director Appointed to the Board
NASDAQ listing standards required the Board to have at least three independent directors within one year of the date our common units were listed on NASDAQ. Effective August 3, 2012, Robert A. Innamorati was appointed as an independent director to the Board. Mr. Innamorati has served as President of Robert A. Innamorati & Co. Inc., a private investment and advisory firm, since 1995. He previously served as President of a privately-owned diversified investment company with assets in excess of $1.5 billion from 2007 until 2012. Mr. Innamorati also held positions with Banc One Capital Corporation, Drexel Burnham Lambert & Co. Inc. and Blyth Eastman Dillon & Co., Inc. He previously served for six years as a special agent with the United States Secret Service in Washington, D.C. and two years in the United States Marine Corps Reserves. Mr. Innamorati currently serves as a board member of The Texas Rangers Baseball Club where he serves as chairman of the compensation committee and is a member of the finance committee. Mr. Innamorati has also served as a board member for several private companies. Mr. Innamorati received a B.S. in
Finance from the McIntire School of Commerce and an MBA from the Darden Graduate School of Business Administration, both at the University of Virginia. He also graduated from the U.S. Treasury Department Law Enforcement Officer's and U.S. Secret Service Schools. Upon his appointment to the Board, Mr. Innamorati was granted an award of 1,535 restricted common units under the Memorial Production Partners GP LLC Long-Term Incentive Plan, of which one-third will vest on the first, second, and third anniversaries of the date of grant.
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. During 2012, natural gas futures traded on the NYMEX fell below $2.00 per MMBtu for the first time in over a decade as a result of supply and demand fundamentals. The decline in gas prices is primarily a result of growing gas production associated with discoveries of significant gas reserves in United States shale plays, combined with the warmer than normal winter of 2011-2012, which has resulted in gas storage levels being at historically high levels. 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 enter into commodity derivative contracts covering approximately 65% to 85% of our targeted average net production over a three-to-five year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Our revolving credit facility contains various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price swap hedges exceeding a certain percentage of production. By removing a significant portion of this price volatility on our future production through September 2017, we have mitigated, but not eliminated, the potential effects of changing commodity prices on our cash flows from operations for those periods.
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. Memorial Resource currently intends to allocate its expected general and administrative costs proportionately based on the relative size of our proved and probable reserves in comparison to Memorial Resource's proved and probable reserves. 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;
• 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.
We are required to comply with certain Adjusted EBITDA-related metrics under our revolving credit facility.
Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, 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; and
• the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units.
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 (in thousands):
For the Three Months For the Six Months
Ended June 30, Ended June 30,
2012 2011 2012 2011
(Predecessor) (Predecessor)
(Recasted) (Recasted)
Calculation of Adjusted EBITDA:
Net income (loss) $ (415 ) $ 64,459 $ 21,642 $ 62,515
Interest expense 3,577 2,206 4,901 3,240
Deferred income tax expense - 122 183 122
DD&A 7,754 7,661 15,012 13,413
Impairment - 2,893 - 2,893
Accretion of AROs 274 265 562 485
Unrealized (gains) losses on
commodity derivative instruments 4,851 (2,046 ) (10,677 ) 367
Gain on sale of properties (192 ) (62,721 ) (192 ) (62,729 )
Acquisition related expenses 285 811 398 811
Unit-based compensation expense 327 - 575 -
Exploration costs 414 56 414 56
Net operating cash flow from
acquisitions, effective date
through closing date 1,888 - 1,888 -
Adjusted EBITDA $ 18,763 $ 13,706 $ 34,706 $ 21,173
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For the Three Months For the Six Months
Ended June 30, Ended June 30,
2012 2011 2012 2011
(Predecessor) (Predecessor)
(Recasted) (Recasted)
Reconciliation of Net Cash from
Operating Activities to Adjusted
EBITDA:
Net cash provided by operating
activities $ 11,783 $ 6,966 $ 27,414 $ 11,659
Changes in working capital 3,079 2,484 2,345 4,137
Interest expense 3,577 2,206 4,901 3,240
Unrealized (loss) gain on
interest rate swaps (2,135 ) (472 ) (2,397 ) (299 )
Premiums paid for derivatives - 2,847 - 2,847
Premiums received for
derivatives - (1,008 ) - (1,008 )
Amortization of deferred
financing fees (128 ) (128 ) (257 ) (214 )
Acquisition related expenses 285 811 398 811
Exploration costs 414 - 414 -
Net operating cash flow from
acquisitions, effective date
through closing date 1,888 - 1,888 -
Adjusted EBITDA $ 18,763 $ 13,706 $ 34,706 $ 21,173
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Critical Accounting Policies and Estimates
A discussion of our critical accounting policies and estimates is included in our 2011 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 and six months ended June 30, 2012 have been derived from our consolidated financial statements. The results of operations for the three and six months ended June 30, 2011 are presented on a combined basis, consisting of the combined financial information of our predecessor. The historical financial data of our predecessor consists of the combined financial data of BlueStone Natural Resources Holdings, LLC, certain oil and natural gas properties owned by Classic and for periods after April 8, 2011, certain oil and natural gas properties owned by WHT. The results of operations covering periods prior to the closing of our IPO on December 14, 2011 may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods. Furthermore, our acquisitions of oil and gas properties from Memorial Resource in April and May 2012 were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at Memorial Resource's carrying value and our consolidated and predecessor financial statements previously filed with the SEC and presented herein were recast to include the financial position and results attributable to these oil and gas properties for all periods presented on a combined basis. See "- Significant Current Developments" for additional information. The following table summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.
For the Three Months For the Six Months
Ended June 30, Ended June 30,
2012 2011 2012 2011
(Predecessor) (Predecessor)
(Recasted) (Recasted)
Revenues:
Oil & natural gas sales $ 16,639 $ 23,027 $ 35,399 $ 37,209
Other income 31 149 141 252
Total revenues $ 16,670 $ 23,176 $ 35,540 $ 37,461
Costs and expenses:
. . .
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