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LRE > SEC Filings for LRE > Form 10-K on 12-Mar-2014All Recent SEC Filings

Show all filings for LRR ENERGY, L.P.

Form 10-K for LRR ENERGY, L.P.


12-Mar-2014

Annual Report


ITEM 7. 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 financial statements and related notes contained in "Item 8. Financial Statements and Supplementary Data." The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. These forward-looking statements are subject to events, risks, assumptions and uncertainties that may be outside our control, including, among other things, the risk factors discussed in Item 1A of this Annual Report. Our actual results could differ materially from those discussed in these forward-looking statements. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Statement Regarding Forward-Looking Information" in the front of this Annual Report.


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Overview

LRR Energy, L.P. ("we," "us," "our," or the "Partnership") is a Delaware limited partnership formed in April 2011 by Lime Rock Management LP ("Lime Rock Management"), an affiliate of Lime Rock Resources A, L.P. ("LRR A"), Lime Rock Resources B, L.P. ("LRR B") and Lime Rock Resources C, L.P. ("LRR C"), to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles. LRR A, LRR B and LRR C were formed by Lime Rock Management in July 2005 for the purpose of acquiring mature, low-risk producing oil and natural gas properties with long-lived production profiles. As used herein, references to "Fund I" or "predecessor" refer collectively to LRR A, LRR B and LRR C; references to "Fund II" refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.; and references to "Fund III" refer collectively to Lime Rock Resources III-A, L.P. and Lime Rock Resources III-C, L.P. References to "Lime Rock Resources" refer collectively to Fund I, Fund II, and Fund III.

Our properties are located in the Permian Basin region in West Texas and southeast New Mexico, the Mid-Continent region in Oklahoma and East Texas and the Gulf Coast region in Texas. These properties consist of working interests in 759 gross (652 net) producing wells, of which we owned a 86% average working interest. As of December 31, 2013, our total estimated proved reserves were 30.1 MMBoe, of which 49% were oil and NGLs as measured by volume, 71% were proved developed producing and 17% were proved developed non-producing. As of December 31, 2013, our estimated proved reserves had a standardized measure of $392.6 million.

Of our total estimated proved reserves as of December 31, 2013, 16.5 MMBoe, or 55%, are located in the Permian Basin region; 10.6 MMBoe, or 35%, are located in the Mid-Continent region; and 3.0 MMBoe, or 10%, are located in the Gulf Coast region.

Contribution of Properties

In connection with the completion of our initial public offering ("IPO") on November 16, 2011, pursuant to a contribution, conveyance and assumption agreement, we acquired specified oil and natural gas properties and related net profits interests and operations and certain commodity derivative contracts (the "Partnership Properties") owned by LRR A, LRR B, and LRR C. Fund I received total consideration for the Partnership Properties of 5,049,600 common units, 6,720,000 subordinated units, $311.2 million in cash and the assumption of $27.3 million of LRR A's indebtedness. For further discussion regarding our IPO, please see Note 10 to the consolidated/combined condensed financial statements included in this report.

On June 1, 2012, we completed an acquisition from Fund I of certain oil and natural gas properties located in the Permian Basin region of New Mexico and onshore Gulf Coast region of Texas for $65.1 million in cash consideration (the "June 2012 Acquisition"). The June 2012 Acquisition was effective as of March 1, 2012. In September 2012, we received $1.1 million in cash from Fund I related to post-closing adjustments to the purchase price.

On January 3, 2013, we completed an acquisition from Fund I of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma for a purchase price of $21.0 million, subject to customary purchase price adjustments (the "January 2013 Acquisition"). In addition, as part of the January 2013 Acquisition, we acquired in the money commodity hedge contracts valued at approximately $1.7 million at the closing of the January 2013 Acquisition. The January 2013 Acquisition was effective October 1, 2012. In June 2013, we paid $0.4 million in cash to Fund I related to post-closing adjustments to the purchase price.

On April 1, 2013, we completed an acquisition of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma and crude oil hedges from Fund II for a purchase price of $38.2 million (the "April 2013 Acquisition"). As part of the April 2013 Acquisition, we acquired in the money crude oil hedges valued at approximately $0.4 million as of the closing of the April 2013 Acquisition. The April 2013 Acquisition was effective April 1, 2013.


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            How We Conduct Our Business and Evaluate Our Operations



We use a variety of financial and operational metrics to assess the performance
of our oil and natural gas operations, including:



          oil, NGLs and natural gas production volumes;

          realized prices on the sale of oil, NGLs and natural gas, including
the effect of our commodity derivative contracts;

          lease operating expenses;

          production and ad valorem taxes;

          general and administrative expenses;

          Adjusted EBITDA; and

          Distributable Cash Flow.

Production Volumes

Production volumes directly impact our results of operations. For more information about our production volumes, please read "Financial and Operating Data" below.

Realized Prices on the Sale of Oil, NGLs and Natural Gas

Factors Affecting the Sales Price of Oil, NGLs and Natural Gas. We market our oil, NGLs and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil, NGLs and natural gas 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.

Oil Prices. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil's American Petroleum Institute, or API, gravity and (2) the oil's percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value, and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content ("sweet" oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil ("sour" oil).

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the produced oil's proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major trading and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).

The oil produced from our properties is a combination of sweet and sour oil, varying by location. We sell our oil at the NYMEX-WTI price, which is adjusted for quality and transportation differentials, depending primarily on location and purchaser. The differential varies, but our oil normally sells at a discount to the NYMEX-WTI price.

Natural Gas Prices. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO2 and other inert content by volume. Wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO2 content sells at a premium to natural gas with high sulfur and CO2 content because of the added cost to separate the sulfur and CO2 from the natural gas to render it marketable. The wet natural gas is processed in third-party natural gas plants and residue natural gas as well as NGLs are recovered and sold. The dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.


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Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas' proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant, which is generally in the form of percentage of proceeds. The differential varies, but our natural gas normally sells at a discount to the NYMEX-Henry Hub price.

NGL Prices. Gas produced from a well that is fused with NGLs is referred to as "wet gas." Wet gas is generally sold at the wellhead or transported to a gas processing plant where the NGLs are separated from the wet gas, leaving NGL component products and "dry gas" residue. Both the NGLs and dry gas residue are transported from or sold at a gas processing plant's "tailgate." The NGLs recovered from the processing of our wet gas are sold as blended NGL barrels at a Mont Belvieu or Conway posted price, which is representative of the weighted average market value of the five primary NGL component products. For the majority of the properties that we operate that produce wet gas, we have agreements in place with gas plants in the various regions to process this natural gas in order to receive the revenue benefit of the NGLs that are generated from processing.

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2013, the NYMEX-WTI oil price ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $4.52 per MMBtu to a low of $3.08 per MMBtu. For the five years ended December 31, 2013, the NYMEX-WTI oil price ranged from a high of $113.93 per Bbl to a low of $33.98 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $7.51 per MMBtu to a low of $1.84 per MMBtu. As of March 7, 2014, the NYMEX-WTI oil spot price was $102.58 per Bbl and the NYMEX-Henry Hub natural gas spot price was $4.77 per MMBtu.

Commodity Derivative Contracts. We enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Our strategy includes entering into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over a three-to-five year period at a given point of time, although we may from time to time hedge more or less than this approximate range.

For a summary of volumes of our production covered by commodity derivative contracts and the average prices at which the production is hedged as of December 31, 2013, please refer to "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."

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. Expenses for utilities, direct labor, water injection and disposal, and materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative costs or production and other taxes. 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.

A majority of our lease operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. As these costs are driven not only by volumes of oil, NGLs and natural gas produced but also volumes of water produced, fields that have a high percentage of water production relative to oil, NGLs and natural gas production, also known as a high water cut, will experience higher levels of costs for each Bbl of oil or NGL or Mcf of natural gas produced.

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. We typically evaluate our oil, NGL and natural gas operating costs on a per Boe basis. This unit rate allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers.


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Production and Ad Valorem Taxes

The various states in which we operate regulate the development, production, gathering and sale of oil and natural gas, including imposing production taxes and requirements for obtaining drilling permits. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; however, these valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

General and Administrative Expenses

We have entered into a services agreement with Lime Rock Management and Lime Rock Resources Operating Company, Inc. ("ServCo") pursuant to which management, administrative and operating services are provided to our general partner and us to manage and operate our business. Our general partner reimburses Lime Rock Management and ServCo for all costs and services they incur on our general partner's and our behalf. Under the services agreement, our general partner will reimburse each of Lime Rock Management and ServCo, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. For further information regarding the services agreement, please read "Item 13. Certain Relationships and Related Transactions, and Director Independence - Services Agreement."

Adjusted EBITDA and Distributable Cash Flow

Adjusted EBITDA and Distributable Cash Flow are used as supplemental financial measures 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 sufficient cash flow to make distributions to our unitholders.

Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income, operating income or any other measure of financial performance presented in accordance with GAAP. Our Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA or Distributable Cash Flow in the same manner. For further discussion of these non-GAAP financial measures, please read "Item 6. Selected Financial Data - Non-GAAP Financial Measures."

Trends and 2014 Outlook

We expect to spend approximately $34 million of total capital expenditures on the development of our oil and natural gas properties in 2014, including approximately $20 million of maintenance capital expenditures. Maintenance capital expenditures represent our estimate of the amount of capital required on average per year to maintain our production over the long term. We expect to spend the remaining $14 million of estimated expenditures primarily on projects designed to reduce operating costs and potentially grow production. The estimated capital expenditures for 2014 do not include any amounts for acquisitions of oil and natural gas properties.

The estimate of total capital expenditures provided above sets forth management's best estimate based on current and anticipated market conditions and is based on current expectations as to the level of capital expenditures, which in turn depends on the amount of oil, natural gas and NGLs we produce, oil, natural gas and NGL prices, the prices at which we sell our oil, natural gas and NGL production, the level of our operating costs and the prices at which we enter into commodity derivative contracts.

Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and are expected to be volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include the discovery of substantial


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accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves, North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Please read "Item 1A. Risk Factors."

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we have entered into commodity derivative contracts, and we intend to enter into commodity derivative contracts in the future, to reduce cash flow volatility. Please read "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for a summary of volumes of our production covered by commodity derivative contracts and the average prices at which the production is hedged through 2017.

As an oil and natural gas company, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. Our future growth will depend on our ability to continue to add estimated reserves in excess of our production. We plan to maintain our focus on adding reserves through acquisitions and exploitation projects and improving the economics of producing oil and natural gas from our existing fields in lieu of higher-risk exploration projects. We expect that these acquisition opportunities may come from Lime Rock Resources and possibly from Lime Rock Partners and its affiliates and also from unrelated third parties. Our ability to add proved reserves through acquisitions and exploitation projects is dependent upon many factors, including our ability to successfully identify and close acquisitions, raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

Financial and Operating Data

Our discussion and analysis of the results of operations below discusses the Partnership's and predecessor's results of operations separately. Because the historical results of our predecessor include results for both the properties conveyed to us in connection with our IPO and properties retained by our predecessor, we do not consider the historical results of our predecessor to be indicative of our future results.

The Partnership Properties acquired in the IPO, June 2012 Acquisition, January 2013 Acquisition and April 2013 Acquisition were deemed to be transactions between entities under common control. As a result, our financial statements were revised to include the activities of such assets for all periods presented, similar to a pooling of interests, and to include the financial position, results of operations and cash flows of the assets acquired and liabilities assumed. The table set forth below includes recast historical financial and operating information attributable to previous acquisitions from Fund I and Fund II as if we owned the properties for all periods presented in our consolidated financial statements.

                                                         Partnership                          Predecessor
                                      Year Ended       Year Ended         November 16        January 1 to
                                     December 31,     December 31,      to December 31,      November 15,
                                         2013             2012               2011                2011
Revenues (in thousands):
Oil sales                            $      77,181    $      72,916    $           9,766     $      59,605
Natural gas sales                           26,800           23,502                3,976            35,883
Natural gas liquids sales                   10,147           11,627                1,976            14,500
Gain on commodity derivative
instruments, net                               781           12,748               12,287            22,027
Other income                                   186               45                    -               159
Total revenues                             115,095          120,838               28,005           132,174


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                                                       Partnership                        Predecessor
                                      Year Ended       Year Ended       November 16       January 1 to
                                     December 31,     December 31,    to December 31,     November 15,
                                         2013             2012             2011               2011
Expenses (in thousands):
Lease operating expense                     25,397          29,069              3,193           21,391
Production and ad valorem taxes              8,614           7,790              1,076            7,763
Depletion and depreciation                  43,420          46,928              5,876           37,206
Impairment of oil and natural gas
properties                                  63,663           3,544                  -           16,765
Management fees                                  -               -                  -            5,435
General and administrative
expense                                     11,965          13,758              1,892            5,149
Interest expense                             9,235           6,596                604              919
(Gain) loss on interest rate
derivative instruments, net                 (1,256 )         4,650                  -              133

Production: (1), (2)
Oil (MBbls)                                    837             834                104              657
Natural gas (MMcf)                           7,246           8,487              1,156            8,606
NGLs (MBbls)                                   315             311                 35              269
Total (MBoe)                                 2,360           2,560                332            2,360
Average net production (Boe/d)               6,466           6,995              7,217            7,398



(1) The Red Lake area constituted approximately 34% of our estimated proved reserves as of December 31, 2013. Our production from the Red Lake area was 803 MBoe, 707 MBoe and 79 MBoe for the years ended December 31, 2013 and 2012 and the period from November 16 to December 31, 2011, respectively. Our predecessor's production from the Red Lake area was 473 MBoe for the period from January 1 to November 15, 2011.

(2) The Potato Hills field constituted approximately 20% of our estimated proved reserves as of December 31, 2013. Our production from the Potato Hills field was 471 MBoe, 531 MBoe and 72 MBoe for the years ended December 31, 2013 and 2012 and the period from November 16 to December 31, 2011, respectively. Our predecessor's production from the Potato Hills field was 527 MBoe for the period from January 1 to November 15, 2011.

                                                           Partnership                          Predecessor
                                        Year Ended       Year Ended         November 16        January 1 to
                                       December 31,     December 31,      to December 31,      November 15,
                                           2013             2012               2011                2011

Average sales price:
Oil (per Bbl):
Sales price                            $       92.21    $       87.43    $           93.90     $       90.72
Effect of settled commodity
derivative instruments (1)                     (2.45 )           4.38                 6.89            (10.66 )
Realized sales price                   $       89.76    $       91.81    $          100.79     $       80.06

Natural gas (per Mcf):
Sales price                            $        3.70    $        2.77    $            3.44     $        4.17
Effect of settled commodity
derivative instruments(1)                       1.44             2.13                 2.87              1.92
Realized sales price                   $        5.14    $        4.90    $            6.31     $        6.09
. . .
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