Exhibit 99.2
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 Exhibit 99.3. 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 our Annual Report on Form 10-K for the year ended December 31, 2012. 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. Please read “Cautionary Statement Regarding Forward-Looking Information” in the front of our Annual Report on Form 10-K.
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 and references to “Fund II” refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. References to “Lime Rock Resources” refer collectively to Fund I and Fund II. Fund I and Fund II are managed by Lime Rock Management and pay a management fee to Lime Rock Management. In addition, Fund I and Fund II also receive administrative services from, and pay an administrative services fee to, Lime Rock Resources Operating Company, Inc. (“ServCo”).
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 717 gross (626 net) producing wells, of which we owned an approximate 87% average working interest. As of December 31, 2012, our total estimated proved reserves were approximately 27.9 MMBoe, of which approximately 47% were oil and NGLs as measured by volume, approximately 71% were proved developed producing and approximately 15% were proved developed non-producing. As of December 31, 2012, our estimated proved reserves had a standardized measure of $325.2 million.
Of our total estimated proved reserves as of December 31, 2012, 17.0 MMBoe, or approximately 61%, are located in the Permian Basin region; 7.6 MMBoe, or approximately 27%, are located in the Mid-Continent region; and 3.3 MMBoe, or approximately 12%, are located in the Gulf Coast region.
Contribution of Properties
In connection with the completion of our 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 (the “Transferred 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 “Transaction”). The Transaction was effective as of March 1,
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2012. In September 2012, we received $1.1 million in cash from Fund I related to post-closing adjustments to the purchase price for the acquisition.
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 as of 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 from Fund II of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma 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 January 2013 Acquisition and April 2013 Acquisition are considered to be transactions between entities under common control. Our Management’s Discussion and Analysis has been retrospectively adjusted to include the results attributable to these acquisitions with Fund I and Fund II as if we owned the properties for all periods presented in our consolidated financial statements. Please refer to Note 2 of our financial statements included in Exhibit 99.3 regarding the retrospective adjustments.
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;
· general and administrative expenses;
· net cash provided by operating activities;
· 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
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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.
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, 2012, the NYMEX-WTI oil price ranged from a high of $109.49 per Bbl to a low of $77.69 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $3.77 per MMBtu to a low of $1.84 per MMBtu. For the five years ended December 31, 2012, the NYMEX-WTI oil price ranged from a high of $145.29 per Bbl to a low of $31.41 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $13.31 per MMBtu to a low of $1.84 per MMBtu. As of March 8, 2013, the NYMEX-WTI oil spot price was $91.95 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.58 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.
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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, 2012, 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.
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 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.”
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Trends and 2013 Outlook
We expect to spend approximately $28 million of total capital expenditures on the development of our oil and natural gas properties in 2013, including approximately $19.2 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 $8.8 million of estimated expenditures primarily on projects designed to reduce operating costs and potentially growth capital. The estimated capital expenditures for 2013 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 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.
Because Fund I affiliates own 100% of our general partner and because Fund I owns 5,049,600 common units and all of our 6,720,000 subordinated units, representing an aggregate 52.4% limited partner interest in us, each acquisition of assets from Fund I is considered a transfer of net assets between entities under common control. We have also determined that acquisitions from Fund II are considered to be transfers of net assets between entities under common control. As a result, we are required to revise our financial statements to include the activities of such
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assets for all periods presented, similar to a pooling of interests, to include the financial position, results of operations and cash flows of the assets acquired and liabilities assumed. The table set forth below includes the results attributable to the acquisitions with Fund I and Fund II as if we owned the properties for all periods presented in our consolidated financial statements.
| | Partnership | | | Predecessor | |
| | Year Ended | | November 16 | | | January 1 to | | Year Ended | |
| | December 31, | | to December 31, | | | November 15, | | December 31, | |
| | 2012 | | 2011 | | | 2011 | | 2010 | |
Revenues (in thousands): | | | | | | | | | | |
Oil sales | | $ | 72,916 | | $ | 9,766 | | | $ | 59,605 | | $ | 52,670 | |
Natural gas sales | | 23,502 | | 3,976 | | | 35,883 | | 48,088 | |
Natural gas liquids sales | | 11,627 | | 1,976 | | | 14,500 | | 14,748 | |
Realized gain on commodity derivative instruments | | 23,350 | | 4,015 | | | 9,353 | | 48,029 | |
Unrealized gain (loss) on commodity derivative instruments | | (10,602 | ) | 8,272 | | | 12,674 | | (23,964 | ) |
Other income | | 45 | | — | | | 159 | | 116 | |
Total revenues | | 120,838 | | 28,005 | | | 132,174 | | 139,687 | |
| | | | | | | | | | |
Expenses (in thousands): | | | | | | | | | | |
Lease operating expense | | 29,069 | | 3,193 | | | 21,391 | | 23,804 | |
Production and ad valorem taxes | | 7,790 | | 1,076 | | | 7,763 | | 9,320 | |
Depletion and depreciation | | 46,928 | | 5,876 | | | 37,206 | | 55,828 | |
Impairment of oil and natural gas properties | | 3,544 | | — | | | 16,765 | | 11,712 | |
Management fees | | — | | — | | | 5,435 | | 6,104 | |
General and administrative expense | | 13,758 | | 1,892 | | | 5,149 | | 5,293 | (1) |
Interest expense | | 6,596 | | 604 | | | 919 | | 3,223 | |
Realized gain (loss) on interest rate derivative instruments | | (465 | ) | — | | | 574 | | 649 | |
| | | | | | | | | | |
Production: (2), (3) | | | | | | | | | | |
Oil (MBbls) | | 834 | | 104 | | | 657 | | 698 | |
Natural gas (MMcf) | | 8,487 | | 1,156 | | | 8,606 | | 11,287 | |
NGLs (MBbls) | | 311 | | 35 | | | 269 | | 376 | |
Total (MBoe) | | 2,560 | | 332 | | | 2,360 | | 2,955 | |
Average net production (Boe/d) | | 6,995 | | 7,217 | | | 7,398 | | 8,096 | |
| | | | | | | | | | | | | | |
(1) General and administrative expenses for the year ended December 31, 2010 include a $2.5 million finder’s fee incurred in connection with the Potato Hills acquisition.
(2) The Red Lake area constituted approximately 39% of our estimated proved reserves as of December 31, 2012. Our production from the Red Lake area was 707 MBoe and 79 MBoe for the year ended December 31, 2012 and the period from November 16 to December 31, 2011, respectively. Our predecessor’s production from the Red Lake area was 473 MBoe and 518 MBoe for the period from January 1 to November 15, 2011 and the year ended December 31, 2010, respectively.
(3) The Potato Hills field constituted approximately 24% of our estimated proved reserves as of December 31, 2012. Our production from the Potato Hills field was 531 MBoe and 72 MBoe for the year ended December 31, 2012 and the period from November 16 to December 31, 2011, respectively. Our predecessor’s production from the Potato Hills field was 527 MBoe and 614 MBoe for the period from January 1 to November 15, 2011 and the year ended December 31, 2010, respectively.
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| | Partnership | | | Predecessor | |
| | Year Ended | | November 16 | | | January 1 to | | Year Ended | |
| | December 31, | | to December 31, | | | November 15, | | December 31, | |
| | 2012 | | 2011 | | | 2011 | | 2010 | |
| | | | | | | | | | |
Average sales price: | | | | | | | | | | |
Oil (per Bbl): | | | | | | | | | | |
Sales price | | $ | 87.43 | | $ | 93.90 | | | $ | 90.72 | | $ | 75.46 | |
Effect of realized commodity derivative instruments (1) | | 4.38 | | 6.89 | | | (10.66 | ) | 23.15 | |
Realized sales price | | $ | 91.81 | | $ | 100.79 | | | $ | 80.06 | | $ | 98.61 | |
| | | | | | | | | | |
Natural gas (per Mcf): | | | | | | | | | | |
Sales price | | $ | 2.77 | | $ | 3.44 | | | $ | 4.17 | | $ | 4.26 | |
Effect of realized commodity derivative instruments(1) | | 2.13 | | 2.87 | | | 1.92 | | 2.82 | |
Realized sales price | | $ | 4.90 | | $ | 6.31 | | | $ | 6.09 | | $ | 7.08 | |
| | | | | | | | | | |
NGLs (per Bbl) | | | | | | | | | | |
Sales price | | $ | 37.39 | | $ | 56.46 | | | $ | 53.90 | | $ | 39.22 | |
Effect of realized commodity derivative instruments(1) | | 5.22 | | (0.71 | ) | | (0.65 | ) | — | |
Realized sales price | | $ | 42.61 | | $ | 55.75 | | | $ | 53.25 | | $ | 39.22 | |
| | | | | | | | | | |
Average unit costs per Boe: | | | | | | | | | | |
Lease operating expenses | | $ | 11.36 | | $ | 9.63 | | | $ | 9.06 | | $ | 8.06 | |
Production and ad valorem taxes | | $ | 3.04 | | $ | 3.24 | | | $ | 3.29 | | $ | 3.15 | |
Management fees | | $ | — | | $ | — | | | $ | 2.30 | | $ | 2.07 | |
General and administrative expenses | | $ | 5.38 | | $ | 5.70 | | | $ | 2.18 | | $ | 1.79 | |
Depletion and depreciation | | $ | 18.33 | | $ | 17.72 | | | $ | 15.76 | | $ | 18.89 | |
(1) Realized gains (losses) on commodity derivative instruments were $9.12 and $12.11 per Boe for the year ended December 31, 2012 and the period from November 16 to December 31, 2011, respectively. Realized gains (losses) on commodity derivative instruments were $3.96 and $16.25 per Boe, for the period from January 1 to November 15, 2011 and the year ended December 31, 2010, respectively.
Partnership’s Results of Operations
As noted above, as a result of being under common control with Fund I and Fund II, we are required to retrospectively adjust our financial statements to include the results of operations of the properties acquired. The discussion below includes the results attributable to the acquisitions with Fund I and Fund II as if we owned the properties for all periods presented in our consolidated financial statements.
Our Results for the Year Ended December 31, 2012
We recorded net income of $6.8 million for the year ended December 31, 2012. This net income was primarily driven by total revenues of $120.8 million offset by lease operating expenses of $29.1 million, production and ad valorem taxes of $7.8 million, depletion and depreciation of $46.9 million and general and administrative expenses of $13.8 million.
Sales Revenues. Sales revenues of $108.0 million for the period consisted of oil sales of $72.9 million, natural gas sales of $23.5 million and NGL sales of $11.6 million. Our production volumes for the period included 1,145 MBbls of oil and NGLs and 8,487 MMcf of natural gas, or 3,128 Bbl/d of oil and NGLs and 23,189 Mcf/d of natural gas. On an equivalent basis, production for the period was 2,560 MBoe, or 6,995 Boe/d.
Our average sales price per Bbl for oil and NGLs for the period, excluding the effect of commodity derivative contracts, was $87.43 and $37.39, respectively. Our average sales price per Mcf of natural gas, excluding the effect of commodity derivative contracts, was $2.77.
During the third week in February 2012 and through the second week in March 2012, approximately 1,515 Bbls/d and 1.7 MMcf/d of our Red Lake field production was entirely shut-in due to a compression system upgrade
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at the third party gas plant that processes natural gas for our Red Lake field. The upgrade was initially expected to last 7 days, but it experienced delays and took 21 days to complete.
Relating to the Pecos Slope field curtailment previously disclosed in our periodic reports filed with the SEC, approximately 1.0 MMcf/d of production was curtailed during 2012 due to the gas containing a nitrogen percentage greater than our gas purchaser’s specification. The curtailment is expected to remain at this level until a field-wide nitrogen rejection facility is installed in the second quarter of 2013 by the third-party gas gathering company. The actual timing and amount of resumed production may differ from these estimates.
Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, we recorded a net gain from our commodity hedging program for the period of approximately $12.8 million, which is comprised of a realized gain of approximately $23.4 million and an unrealized loss of approximately $10.6 million.
Lease Operating Expenses. Our lease operating expenses were approximately $29.1 million, or $11.36 per Boe, for the period.
Production and Ad Valorem Taxes. Our production and ad valorem taxes were approximately $7.8 million, or $3.04 per Boe, for the period. Production taxes accounted for approximately $7.1 million and ad valorem taxes for $0.7 million of the total taxes recorded.
Depletion and Depreciation. Our depletion and depreciation expense was approximately $46.9 million, or $18.33 per Boe, for the period.
Impairment of Oil and Natural Gas Properties. We recorded impairment charges of approximately $3.5 million for the year ended December 31, 2012. Approximately $3.1 million of this amount related to a decline in natural gas prices that impacted our proved properties during the first quarter of 2012, and the remaining $0.4 million related to impairments of unproved properties in the third quarter of 2012.
If future oil or natural gas prices decline further, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for such properties and a non-cash impairment charge may be required to be recognized in future periods. As of March 8, 2013, the NYMEX-WTI oil spot price was $91.95 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.58 per MMBtu.
General and Administration Expenses. Our general and administrative expenses were approximately $13.8 million, or $5.38 per Boe, for the year ended December 31, 2012.
Interest Expense. Our interest expense is comprised of interest on our credit facility and term loan, amortization of debt issuance costs and realized gains (losses) on our interest rate derivative instruments. Interest expense was approximately $7.1 million for the year ended December 31, 2012. Unrealized losses on interest rate derivative contracts were approximately $4.2 million for the year ended December 31, 2012 due to a decline in interest rates over the period.
Our Results for the Period from November 16 to December 31, 2011
We recorded net income of $15.1 million during the period from November 16 to December 31, 2011. This net income was primarily driven by total revenues of $28.0 million offset by lease operating expenses of $3.2 million, production and ad valorem taxes of $1.1 million, depletion and depreciation of $5.9 million and general and administrative expenses of $1.9 million.
Sales Revenues. Sales revenues of $15.8 million for the period consisted of oil sales of $9.8 million, natural gas sales of $4.0 million and NGL sales of $2.0 million. Our production volumes for the period included 139 MBbls of oil and NGLs and 1,156 MMcf of natural gas, or 3,022 Bbl/d of oil and NGLs and 25,130 Mcf/d of natural gas. On an equivalent basis, production for the period was 332 MBoe, or 7,217 Boe/d.
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Our average sales price per Bbl for oil and NGLs, excluding the effect of commodity derivative contracts, for the period was $93.90 and $56.46, respectively. Our average sales price per Mcf of natural gas, excluding the effect of commodity derivative contracts, was $3.44.
Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, we recorded a net gain from our commodity hedging program for the period of approximately $12.3 million, which is comprised of a realized gain of approximately $4.0 million and an unrealized gain of approximately $8.3 million.
Lease Operating Expenses. Our lease operating expenses were approximately $3.2 million, or $9.63 per Boe, for the period. The per Boe amount is consistent with our predecessor’s rate for the remainder of 2011.
Production and Ad Valorem Taxes. Our production and ad valorem taxes were approximately $1.1 million, or $3.24 per Boe, for the period. The per Boe amount is consistent with our predecessor’s rate for the remainder of 2011. Production taxes accounted for approximately $1.0 million and ad valorem taxes for $0.1 million of the total taxes recorded.
Depletion and Depreciation. Our depletion and depreciation expense was approximately $5.9 million, or $17.72 per Boe, for the period.
Impairment of Oil and Natural Gas Properties. We did not record any impairment charges during the period.
General and Administration Expenses. Our general and administrative expenses were approximately $1.9 million, or $5.70 per Boe, for the period. The higher per Boe rate than our predecessor is primarily driven by additional expenses related to us being a public company.
Interest Expenses. Our interest expense is comprised of interest on our credit facility and amortization of debt issuance costs. Interest expense was approximately $0.6 million for the period.
Predecessor Results of Operations
Factors Affecting the Comparability of the Historical Financial Results of Our Predecessor
The comparability of our predecessor’s results of operations among the periods presented is impacted by:
· The following acquisitions by our predecessor:
· the Potato Hills acquisition for a purchase price of approximately $104.0 million in February 2010;
· the acquisition of interests in 30 producing oil and natural gas wells located in Texas for a purchase price of approximately $7.5 million in August 2010;
· the acquisition of additional interests in producing oil and natural gas wells located in New Mexico for a purchase price of approximately $1.8 million in October 2010; and
· The following divestiture by our predecessor:
· the divestiture of interests in 17 producing oil and natural gas wells located in New Mexico for approximately $14.3 million in September 2010.
· The 2011 comparison only includes the period up to November 15, 2011 (the date prior to the IPO)
As a result of the factors listed above, historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.
Period from January 1 to November 15, 2011 Compared to the Year Ended December 31, 2010
Our predecessor recorded net income of approximately $35.7 million for the period from January 1 to November 15, 2011 compared to $22.3 million for the year ended December 31, 2010. This increase in net income was primarily driven by an increase in gains on derivative instruments.
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Sales Revenues. Revenues from oil, NGLs and natural gas sales for the period from January 1 to November 15, 2011 were $110.0 million compared to $115.5 million for the year ended December 31, 2010. The decrease in revenues was primarily due to a decline in natural gas sales to $35.9 million for the period from January 1 to November 15, 2011 from $48.1 million for the year ended December 31, 2010. This decline was primarily driven by lower natural gas prices in the 2011 period. Oil sales increased to $59.6 million for the period from January 1 to November 15, 2011 from $52.7 million for the year ended December 31, 2010 primarily due to increased oil prices during the period. Natural gas sales were relatively flat between periods.
Our predecessor’s production volumes for the period from January 1 to November 15, 2011 included 926 MBbls of oil and NGLs and 8,606 MMcf of natural gas, or 2,903 Bbl/d of oil and NGLs and 26,978 Mcf/d of natural gas. On an equivalent net basis, production for the period from January 1 to November 15, 2011 was 2,360 MBoe, or 7,398 Boe/d. In comparison, our predecessor’s production volumes for the year ended December 31, 2010 included 1,074 MBbls of oil and NGLs and 11,287 MMcf of natural gas, or 2,942 Bbl/d of oil and NGLs and 30,923 Mcf/d of natural gas. On an equivalent net basis, production for the year ended December 31, 2010 was 2,955 MBoe, or 8,096 Boe/d.
Our predecessor’s average sales price per Bbl for oil and NGLs, excluding the effect of commodity derivative contracts, for the period from January 1 to November 15, 2011 was $90.72 and $53.90, respectively, compared with $75.46 and $39.22, for the year ended December 31, 2010, respectively. Similarly, our predecessor’s average sales price per Mcf of natural gas, excluding the effect of commodity derivative contracts, for the period from January 1 to November 15, 2011 was $4.17 compared with $4.26 for the year ended December 31, 2010.
Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, our predecessor recorded a gain from its commodity hedging program for the period from January 1 to November 15, 2011 of approximately $22.1 million, which is comprised of a realized gain of approximately $9.4 million and an unrealized gain of approximately $12.7 million. For the year ended December 31, 2010, our predecessor recorded a net gain of approximately $24.0 million, which is comprised of a realized gain of approximately $48.0 million, partially offset by an unrealized loss of approximately $24.0 million.
Lease Operating Expenses. Our predecessor’s lease operating expenses were approximately $21.4 million for the period from January 1 to November 15, 2011 compared to approximately $23.8 million for the year ended December 31, 2010. On a per Boe basis, our predecessor’s unit lease operating expenses increased to $9.06 per Boe for the period from January 1 to November 15, 2011 compared to $8.06 per Boe for the year ended December 31, 2010 primarily due to new wells coming online at the Red Lake field and increased saltwater disposal costs at the Red Lake and Coral Canyon fields. During the third quarter of 2011, our predecessor invested capital to help reduce saltwater disposal costs.
Production and Ad Valorem Taxes. Production and ad valorem taxes were approximately $7.8 million for the period from January 1 to November 15, 2011 compared to approximately $9.3 million for the year ended December 31, 2010. The variance is primarily due to changes in the estimates of the appraisals on which our predecessor’s property taxes were calculated. On a per Boe basis, production and ad valorem taxes were $3.29 per Boe for the period from January 1 to November 15, 2011 compared to $3.15 per Boe for the year ended December 31, 2010.
Depletion and Depreciation Expenses. Our predecessor’s depletion and depreciation expenses were approximately $37.2 million, or $15.76 per Boe, for the period from January 1 to November 15, 2011 compared to approximately $55.8 million, or $18.89 per Boe, for the year ended December 31, 2010. The overall decrease was primarily a result of the 2010 impairment described below and the decline in commodity prices in the first quarter of 2010.
Impairment of Oil and Natural Gas Properties. Our predecessor recorded an impairment of approximately $16.8 million in the period from January 1 to November 15, 2011 due to a decline in natural gas prices during the period. An impairment of $11.7 million was recorded during the year ended December 31, 2010 due to a decline in commodity prices in the first quarter of 2010.
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Management Fees. Our predecessor incurs a management fee paid to Lime Rock Management in addition to the direct general and administrative expenses it incurs. The management fee is determined by a formula based on the predecessor’s limited partners’ invested capital or the equity capital commitment in Fund I. The predecessor’s management fees were approximately $5.4 million for the period from January 1 to November 15, 2011 compared to approximately $6.1 million for the year ended December 31, 2010.
General and Administrative Expenses. Our predecessor’s general and administrative expenses were approximately $5.1 million for the period from January 1 to November 15, 2011 compared to approximately $5.3 million for the year ended December 31, 2010. The 2010 amount included a $2.5 million finder’s fee incurred in connection with the Potato Hills acquisition in 2010 which was offset by transactions costs associated with our IPO. General and administrative expenses, on a per Boe basis, were $2.18 per Boe for the period from January 1 to November 15, 2011 compared to $1.79 per Boe for the year ended December 31, 2010.
Interest Expense. Our predecessor’s interest expense is comprised of interest on its credit facility, debt issuance and financing costs, and realized gains (losses) on its interest rate derivative instruments. Interest expense for the period from January 1 to November 15, 2011 was approximately $1.5 million compared to approximately $3.9 million for the year ended December 31, 2010. This decrease was primarily due the refinancing of the credit facility in 2010.
Liquidity and Capital Resources
Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements depends on our ability to generate cash. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, weather and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.
Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our credit facility and our term loan. We may issue additional equity and debt as needed.
We enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we enter 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 in time, although we may from time to time hedge more or less than this approximate range.
Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and our general partner. In making cash distributions, our general partner attempts to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.
We may borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. In addition, a significant portion of our production is hedged. We are generally required to settle our commodity hedge derivatives within five days of the end of the month. As is typical in the oil and gas industry, we generally do not receive the proceeds from the sale of our hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the derivative contracts, we are required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions. Because we distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production and as a result, we may not grow as quickly as other oil and gas entities or at all.
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We are committed to reinvesting a sufficient amount of our cash flow to fund our exploitation and development capital expenditures in order to maintain our production, and we use, and intend to use in the future, primarily external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to make acquisitions to further increase our production and proved reserves. Because our proved reserves and production decline continually over time and because we do not own any undeveloped properties or leasehold acreage, we will need to make acquisitions to sustain our level of distributions to unitholders over time.
If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our credit facility or term loan, issuances of debt and equity securities or from other sources, such as asset sales. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our credit facility and term loan. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.
As of December 31, 2012, we had borrowing capacity of $72.0 million under our $500 million revolving credit facility ($250 million borrowing base less $178.0 million of outstanding borrowings) and $3.5 million of cash on hand. Based upon current oil and natural gas price expectations and our commodity derivatives positions for the year ending December 31, 2013, which cover 83% of our estimated production from total proved developed producing reserves, we anticipate that our cash on hand, cash flow from operations and available borrowing capacity under our revolving credit facility will provide us sufficient working capital to meet our total planned 2013 capital expenditures of approximately $28 million, of which approximately $19.2 million is maintenance capital, and planned 2013 annualized cash distributions of approximately $43.2 million. During the year ended December 31, 2012, our cash capital expenditures totaled approximately $31.4 million. Our board of directors determines our distribution each quarter and there is no guarantee that the board will maintain or increase our current quarterly distribution of $0.4800 per unit.
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. The primary purpose of maintenance capital is to maintain our production at a steady level over the long term to maintain our distributions per unit. We have estimated our maintenance capital expenditures to be approximately $19.2 million in 2013.
Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The primary purpose of growth capital expenditures is to acquire producing assets that will increase our distributions per unit and secondarily increase the rate of development and production of our existing properties in a manner that is expected to be accretive to our unitholders. Growth capital expenditures may include projects on our existing asset base. Although we may make acquisitions during 2013, including potential acquisitions of producing properties from Lime Rock Resources, we have not estimated any growth capital expenditures related to potential opportunistic acquisitions because we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts.
The amount and timing of our capital expenditures is largely discretionary and within our general partner’s control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, our general partner may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2013. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production. There can be no assurance that our operations and other
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capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.
Credit Agreement
In connection with our IPO, we, as guarantor and our wholly owned subsidiary, LRE Operating, LLC (“OLLC”), as borrower, entered into a senior secured revolving credit facility (as amended, the “Credit Agreement.”) The Credit Agreement is a five-year, $500 million revolving credit facility with a current borrowing base of $250 million.
Our Credit Agreement is reserve-based, and we are permitted to borrow under our Credit Agreement in an amount up to the borrowing base, which is primarily based on the estimated value of our oil, NGL and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In the future, we may be unable to access sufficient capital under our Credit Agreement as a result of (i) a subsequent borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.
A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our Credit Agreement. Additionally, we will not be able to pay distributions to our unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with the Credit Agreement after giving effect to such distribution.
Borrowings under the Credit Agreement are secured by liens on substantially all of our properties, but in any event, not less than 80% of the PV-10 value of our oil and natural gas properties, and all of our equity interests in OLLC and any future guarantor subsidiaries and all of our and our subsidiaries’ other assets including personal property. Additionally, borrowings under the Credit Agreement bear interest, at OLLC’s option, at either (i) the greater of the prime rate as determined by the Administrative Agent, the federal funds effective rate plus 0.50%, and the 30-day adjusted LIBOR plus 1.0%, all of which is subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.
Our Credit Agreement requires maintenance of a ratio of Total Debt (as such term is defined in the Credit Agreement) to EBITDAX, which we refer to as the leverage ratio, of not more than 4.0 to 1.0x, and a ratio of consolidated current assets to consolidated current liabilities, which we refer to as the current ratio, of not less than 1.0 to 1.0x. Our Credit Agreement defines EBITDAX as consolidated net income plus the sum of interest, income taxes, depreciation, depletion, amortization, accretion, impairment charges, exploration expenses and other noncash charges, plus reasonable one-time fees, charges and expenses related to our IPO, our acquisition of the Partnership Properties and the closing of the Credit Agreement or other start up activities, minus all noncash income.
Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our, OLLC’s and any of our subsidiaries’ ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production; and prepay certain indebtedness.
Events of default under the Credit Agreement include, but are not limited to, failure to make payments when due; any material inaccuracy in the representations and warranties of OLLC; the breach of any covenants continuing
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beyond the cure period; a matured payment default under, or other event permitting acceleration of, any other material debt; a change in management or change of control; a bankruptcy or other insolvency event; and certain material adverse effects on our business.
If we fail to perform our obligations under these and other covenants, the revolving credit commitments could be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of December 31, 2012, we were in compliance with all covenants contained in the Credit Agreement.
At December 31, 2012, we had approximately $178.0 million of outstanding borrowings under our Credit Agreement and available borrowing capacity of approximately $72.0 million. As of March 8, 2013, we had approximately $205.0 million of outstanding borrowings under our Credit Agreement and available borrowing capacity of approximately $45.0 million. The increased borrowings were primarily driven by our January 2013 acquisition of oil and natural gas properties from Fund I and working capital borrowings due to the timing of our monthly receipts of cash.
Term Loan Agreement
On June 28, 2012, we, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a Second Lien Credit Agreement (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50 million senior secured second lien term loan to OLLC. OLLC borrowed $50 million under the Term Loan Agreement and used the borrowings to repay outstanding borrowings under the Credit Agreement.
The obligations under the Term Loan Agreement are guaranteed on a joint and several basis by us. The obligations are secured by a second priority mortgage and security interest in all assets of OLLC and us that secure OLLC’s and our existing indebtedness under the Credit Agreement.
Borrowings under the Term Loan Agreement mature on January 20, 2017, and, subject to the terms of the Intercreditor Agreement (as described in the Term Loan Agreement), OLLC has the ability at any time to prepay the Term Loan Agreement without premium or penalty. Borrowings under the Term Loan Agreement bear interest, at OLLC’s option, at either
· the greatest of (i) the prime rate as defined in the Term Loan Agreement, (ii) the federal funds effective rate plus 0.50% and (iii) the 30-day adjusted LIBOR plus 1.0%, all of which is subject to an applicable margin as follows:
· 4.50% through March 31, 2013;
· 6.00% from April 1, 2013 to December 31, 2013; and
· 7.50% from January 1, 2014 to January 20, 2017; or
· the applicable reserve-adjusted LIBOR plus an applicable margin as follows:
· 5.50% through March 31, 2013;
· 7.00% from April 1, 2013 to December 31, 2013; and
· 8.50% from January 1, 2014 to January 20, 2017.
Additionally, the Term Loan Agreement provides for an upfront fee of one percent of the aggregate maximum commitment amount, or $500,000.
The Term Loan Agreement contains various covenants and restrictive provisions which limit the ability of OLLC, us or any of our subsidiaries to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; prepay certain indebtedness; and amend the Credit Agreement or grant any liens to secure any indebtedness under the Credit Agreement.
The Term Loan Agreement also contains covenants that, among other things, require OLLC and us to maintain specified ratios including leverage ratio of Total Debt to EBITDAX of not more than 4.25 to 1.00x; a current ratio of
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consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0x; and an asset coverage ratio of Total Proved PV-10 to Total Debt of not less than 1.50 to 1.00x. As of December 31, 2012, we were in compliance with all covenants contained in the Term Loan Agreement.
The obligations under the Term Loan Agreement and the Credit Agreement are governed by an Intercreditor Agreement with OLLC as borrower and us as parent guarantor, which (i) provides that any liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing the indebtedness under the Term Loan Agreement are subordinate to liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing indebtedness under the Credit Agreement and derivative contracts with lenders and their affiliates and (ii) sets forth the respective rights, obligations and remedies of the lenders under the Credit Agreement with respect to their first-priority liens and the lenders under the Term Loan Agreement with respect to their second-priority liens.
Commodity Derivative Contracts
The following table summarizes, for the periods presented, the weighted average price and notional volumes of our oil, NGL and natural gas swaps, puts and collars in place as of December 31, 2012. The table has been retrospectively adjusted to include derivative contracts acquired from Fund I and Fund II in connection with the January 2013 Acquisition and April 2013 Acquisition. The weighted average price is based on the swap price for oil, NGL and natural gas swaps and the floor price of oil and natural gas collars. We use swaps and collars as a mechanism for managing commodity price risks whereby we pay the counterparty floating prices and receive fixed prices from the counterparty. By entering into the hedge agreements, we mitigate the effect on our cash flows of changes in the prices we receive for our oil and natural gas production. These transactions are settled based upon the NYMEX-WTI price of oil and NYMEX-Henry Hub price of natural gas on the average of the three final trading days of the month, with settlement occurring on the fifth day of the production month.
| | | | | | | | | | Natural Gas | |
| | Oil (NYMEX-WTI) | | NGL (NYMEX-WTI) | | (NYMEX-Henry Hub) | |
| | Weighted Average | | Weighted Average | | Weighted Average | |
Term | | $/Bbl | | Bbls/d | | $/Bbl | | Bbls/d | | $/Mmbtu | | Mmbtu/d | |
| | | | | | | | | | | | | |
2013 | | $ | 95.95 | | 1,915 | | $ | 50.49 | | 395 | | $ | 5.11 | | 21,083 | |
2014 | | $ | 96.61 | | 1,422 | | $ | — | | — | | $ | 5.53 | | 16,649 | |
2015 | | $ | 94.72 | | 1,152 | | $ | — | | — | | $ | 5.72 | | 15,069 | |
2016 | | $ | 86.02 | | 1,089 | | $ | — | | — | | $ | 4.28 | | 13,367 | |
2017 | | $ | 85.75 | | 545 | | $ | — | | — | | $ | 4.61 | | 12,618 | |
The following table summarizes, for the periods presented, our natural gas basis swaps in place as of December 31, 2012. The table has been retrospectively adjusted to include derivative contracts acquired from Fund I and Fund II in connection with the January 2013 Acquisition and April 2013 Acquisition. These contracts are designed to effectively fix a price differential between the NYMEX-Henry Hub price and the index price at which the physical natural gas is sold.
| | Centerpoint East | | Houston Ship Channel | | WAHA | | TEXOK | |
Term | | $/Mmbtu | | Mmbtu/d | | $/Mmbtu | | Mmbtu/d | | $/Mmbtu | | Mmbtu/d | | $/Mmbtu | | Mmbtu/d | |
| | | | | | | | | | | | | | | | | |
2013 | | $ | (0.1877 | ) | 7,985 | | $ | (0.0835 | ) | 4,626 | | $ | (0.1172 | ) | 6,647 | | $ | (0.0992 | ) | 1,143 | |
2014 | | $ | (0.2121 | ) | 6,459 | | $ | (0.0835 | ) | 3,475 | | $ | (0.1290 | ) | 5,245 | | $ | (0.1220 | ) | 919 | |
2015 | | $ | (0.2291 | ) | 5,939 | | $ | (0.0959 | ) | 3,031 | | $ | (0.1380 | ) | 4,777 | | $ | (0.1334 | ) | 846 | |
2016 | | $ | — | | — | | $ | (0.0810 | ) | 2,691 | | $ | (0.1326 | ) | 4,408 | | $ | (0.0975 | ) | 784 | |
Cash Flows
Cash flows provided (used) by type of activity were as follow for the periods indicated (in thousands):
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| | Partnership | | | Predecessor | |
| | Year Ended | | November 16 | | | January 1 to | | Year Ended | |
| | December 31, | | to December 31, | | | November 15, | | December 31, | |
| | 2012 | | 2011 | | | 2011 | | 2010 | |
| | | | | | | | | | |
Net cash provided by (used in): | | | | | | | | | | |
Operating activities | | $ | 77,223 | | $ | 5,523 | | | $ | 84,027 | | $ | 121,269 | |
Investing activities | | (40,433 | ) | (755 | ) | | (44,891 | ) | (125,846 | ) |
Financing activities | | (34,836 | ) | (3,255 | ) | | (38,000 | ) | 1,505 | |
| | | | | | | | | | | | | | |
Operating Activities.
Partnership. Net cash provided by operating activities was approximately $77.2 million for the year ended December 31, 2012 and $5.5 million for the period from November 16 to December 31, 2011. Revenues fluctuate due to the volatility of commodity prices, and therefore our cash provided by operating activities is impacted by the prices received for oil and natural gas sales, as well as levels of production volumes and operating expenses.
Our working capital totaled $19.4 million and $23.1 million at December 31, 2012 and 2011, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $3.5 million and $1.5 million at December 31, 2012 and 2011, respectively.
Predecessor. Net cash provided by operating activities was approximately $84.0 million and $121.3 million for the period from January 1 to November 15, 2011 and the year ended December 31, 2010, respectively. Revenues fluctuated during the periods presented primarily due to the volatility of commodity prices, and therefore our predecessor’s net cash provided by operating activities fluctuated during those periods. Cash provided by operating activities is impacted by the prices received for oil and natural gas sales and levels of production volumes.
Investing Activities.
Partnership. Net cash used in investing activities was approximately $40.4 million for the year ended December 31, 2012 and $0.8 million for the period from November 16 to December 31, 2011, which primarily represented additions to our property and equipment balances during the periods.
Predecessor. Net cash used in investing activities by our predecessor was approximately $44.9 million and $125.8 million for the period from January 1 to November 15, 2011 and the year ended December 31, 2010, respectively. The increased amount of cash used in investing activities in the year ended December 31, 2010 was principally due to the acquisitions of oil and natural gas properties, which included the Potato Hills acquisition in February 2010.
Financing Activities.
Partnership. Cash flows used in financing activities of $34.8 million for the year ended December 31, 2012 included distributions paid to our unitholders of $37.3 million, distributions and contributions to Fund I of $69.2 million and deferred financing costs of $0.6 million, offset by net borrowings of $72.2 million.
Cash flows used in financing activities of $3.3 million for the period from November 16 to December 31, 2011 primarily relates to our IPO. We received $188.5 million of net proceeds from our IPO, $155.8 million from borrowings under our revolving credit facility and $0.4 million from our general partner. We distributed $311.2 million to Fund I as consideration for the Partnership Properties and paid $27.3 million of the debt assumed from LRR A and contributed $3.4 million to Fund I. We also paid IPO transaction costs of $4.7 million and deferred financing costs of $1.4 million.
Predecessor. Net cash provided by (used in) financing activities by our predecessor was approximately $(38.0) million and $1.5 million for the period from January 1 to November 15, 2011 and the year ended December 31, 2010, respectively. In 2011, the cash used in financing activities consisted of distributions of approximately $43.4 million offset by capital contributions of $5.4 million. For 2010, the cash provided by financing activities primarily
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related to $129.0 million of capital contributions for acquisitions, debt borrowings of $8.6 million offset by distributions of $120.9 million, return of capital of $9.3 million and debt repayments of $5.5 million.
We expect to spend approximately $28 million in total capital expenditures in 2013, of which approximately $19.2 million represents maintenance capital expenditures on the development of our oil and natural gas properties in 2013.
We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.4750 per unit per quarter ($1.90 per unit on an annualized basis). Based on the number of common units, subordinated units and general partner units outstanding as of March 8, 2013, distributions to all of our unitholders at the current quarterly distribution rate for 2013 would total approximately $10.8 million.
We intend to pursue acquisitions of long-lived, low-risk producing oil and natural gas properties with reserve exploitation potential. We would expect to finance any significant acquisition of oil and natural gas properties in 2013 though external financing sources, including borrowings under our revolving Credit Agreement and Term Loan Agreement and the issuance of debt and equity securities.
Contractual Obligations
A summary of our contractual obligations as of December 31, 2012 is provided in the following table (in thousands).
| | Obligations Due in Period | |
Contractual Obligation | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | Thereafter | | Total | |
Long-term debt (1) | | $ | — | | $ | — | | $ | — | | $ | 178,000 | | $ | 50,000 | | $ | — | | $ | 228,000 | |
Interest on long-term debt(2) | | 8,283 | | 8,283 | | 8,283 | | 5,646 | | 251 | | — | | 30,746 | |
Total | | $ | 8,283 | | $ | 8,283 | | $ | 8,283 | | $ | 183,646 | | $ | 50,251 | | $ | — | | $ | 258,746 | |
(1) Represents amounts outstanding under our Credit Agreement and Term Loan Agreement as of December 31, 2012. The total balance of our Credit Agreement will mature in July 2016 and the balance on our Term Loan Agreement will mature in January 2017.
(2) Based upon the weighted average interest rate of approximately 2.76% under the Credit Agreement at December 31, 2012 and an unused commitment fee of 0.50% on $72.0 million and the weighted average interest rate of approximately 6.02% under the Term Loan Agreement.
The table above excludes amounts associated with our oil and natural gas property asset retirement obligations. As of December 31, 2012, approximately $34.1 million of such obligations were recorded as liabilities, $0.5 million of which was reflected as current liabilities.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Estimates and assumptions are evaluated on a regular basis. We based our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:
· it requires assumptions to be made that were uncertain at the time the estimate was made; and
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· changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.
Below is a discussion of the more significant accounting policies, estimates and judgments. See “Note 2 — Summary of Significant Accounting Policies” of the Notes to the Consolidated Financial Statements in this report for a discussion of additional accounting policies and estimates made by management.
Transactions Between Entities Under Common Control
Master limited partnerships (“MLPs”) enter into transactions whereby the MLP receives a transfer of certain assets from its sponsor or predecessor for consideration of either cash, units, assumption of debt, or any combination thereof. We account for the net assets received using the carryover book value of Fund I or Fund II as these are transactions between entities under common control. Our historical financial statements have been revised to include the results attributable to the assets contributed from Fund I and Fund II as if we owned such assets for all periods presented by us. The following financial statement items were impacted:
Oil and Natural Gas Properties Received. The book value and related activity of oil and natural gas properties received from Fund I and Fund II is determined using the carrying value of the specific assets contributed.
Asset Retirement Obligations Received. The book value and related activity of asset retirement obligations received from Fund I and Fund II was determined by using the carrying value of the specific liabilities attributable to the assets contributed.
Commodity Derivative Instruments. The fair value of the commodity derivative contracts associated with the properties acquired from Fund I and Fund II.
Oil, Natural Gas and NGL Revenues and Expenses. Oil, natural gas and NGL revenues and expenses related to the properties acquired are based on the actual results of the acquired properties. Historical lease operating statements by individual asset were used as the basis for revenues and direct operating expenses.
Unrealized Gain (Loss) on Commodity Derivative Contracts. Reflects the unrealized gain (loss) on commodity derivative contracts associated with the properties acquired assuming the contracts had been in place as of the date acquired by Fund I and Fund II.
General and Administrative Expense. The general and administrative expense attributable to the properties acquired was determined by the ratio of production for the properties acquired to the respective total Fund I or Fund II production for the period presented.
Oil, NGL and Natural Gas Reserve Quantities
Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Miller and Lents, Ltd. and Netherland, Sewell & Associates, Inc., our independent reserve engineering firms, prepare a fully-engineered reserve and economic evaluation of all our properties on a lease, unit or well-by-well basis, depending on the availability of well-level production data. The estimates of the proved reserves as of December 31, 2012 included in this report are based on reserve reports prepared by Miller and Lents, Ltd. and Netherland, Sewell & Associates, Inc.
We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. Our independent engineering firm adheres to the same guidelines when preparing their reserve reports. The accuracy of our reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various economic assumptions, and the judgments of the individuals preparing the estimates.
Our proved reserve estimates are also a function of many assumptions, all of which could deviate significantly from actual results. For example, when the price of oil and natural gas increases, the economic life of our properties
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is extended, thus increasing estimated proved reserve quantities and making certain projects economically viable. Likewise, if oil and natural gas prices decrease, the properties economic life is reduced and certain projects may become uneconomic, reducing estimated proved reserved quantities. Oil and natural gas price volatility adds to the uncertainty of our reserve quantity estimates. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and natural gas liquids eventually recovered.
Successful Efforts Method of Accounting
We account for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.
We evaluate the impairment of our proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in our estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depletion and depreciation unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
Unproved Properties
Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. We assess unproved properties for impairment quarterly on the basis of our experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors.
Impairment of Oil and Natural Gas Properties
We recorded a non-cash impairment charge of approximately $3.1 million related to our proved oil and natural gas properties during the year ended December 31, 2012. For the period from January 1 to November 15, 2011, our predecessor recorded a non-cash impairment charge of approximately $16.8 million. For the year ended December 31, 2010, our predecessor recorded a non-cash impairment charge of approximately $11.7 million. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charges are included in impairment of oil and natural gas properties in our condensed/combined statements of operations. We recorded no impairment charge of proved oil and natural gas properties for the period from November 16 to December 31, 2011. If future oil and natural gas prices decline during
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2013, the estimated undiscounted cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for our recently acquired properties and a non-cash impairment charge may be required to be recognized in future periods. As of March 8, 2013, the NYMEX-WTI oil spot price was $91.95 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.58 per MMBtu.
Asset Retirement Obligations
The initial estimated asset retirement obligation associated with oil and natural gas properties is recognized at fair value as a liability, with a corresponding increase in the carrying value of oil and natural gas properties when the legal obligation is incurred. Amortization expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.
Revenue Recognition and Natural Gas Balancing
Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. We account for oil and natural gas production imbalances using the sales method, whereby we recognize revenue on all natural gas and oil sold to our customers notwithstanding the fact that its ownership may be less than 100% of the oil and natural gas sold. Liabilities are recorded for imbalances greater than our respective proportionate share of remaining estimated and oil natural gas reserves.
Derivative Contracts and Hedging Activities
Current accounting rules require that all derivative contracts, other than those that meet specific exclusions, be recorded at fair value. Quoted market prices are the best evidence of fair value. If quotations are not available, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or on other valuation techniques.
Our derivative contracts are either exchange-traded or transacted in an over-the-counter market. Valuation is determined by reference to readily available public data.
We recognize all of our derivative contracts as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative contract depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative contracts that are designated and qualify as hedging instruments, we designate the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. For derivative contracts not designated as hedging instruments, the gain or loss is recognized in current earnings during the period of change. None of our derivatives was designated as a hedging instrument during 2012, 2011 or 2010.
Recently Issued Accounting Pronouncements
In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” The Amendments explain how to measure fair value and change the wording used to describe many of the fair value requirements in GAAP, but do not require additional fair value measurements. The guidance became effective for interim and annual periods beginning on or after December 15, 2011. We adopted these amendments on January 1, 2012 and they did not have a material impact on our consolidated financial position, results of operations or cash flows.
In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The amendments in this update require enhanced disclosures around financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The amendments are effective during interim and
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annual periods beginning on or after January 1, 2013. We do not expect this guidance to have a material impact on our consolidated financial position, results of operations or cash flows.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2012, 2011 and 2010. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy, and we tend to experience inflationary pressure on the cost of oilfield services and equipment, as increasing oil and natural gas prices increase drilling activity in our areas of operations.
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements.
Supplemental Disclosures Regarding LRR Energy, L.P. Prior to IPO
The following table provides selected results for the properties conveyed to us in connection with our IPO and for those properties subsequently acquired from Fund I in June 2012 and January 2013. The following information is for informational purposes only and should not be considered indicative of future results.
| | Period from | | | |
| | January 1 to | | Year Ended | |
| | November 15, | | December 31, | |
| | 2011 | | 2010 | |
| | | | | |
Production: | | | | | |
Oil (MBbls) | | 602 | | 616 | |
Natural gas (MMcf) | | 8,441 | | 10,930 | |
NGLs (MBbls) | | 257 | | 361 | |
Total (MBoe) | | 2,265 | | 2,799 | |
Average net production (Boe/d) | | 7,101 | | 7,668 | |
| | | | | |
Revenues (in thousands): | | | | | |
Oil | | $ | 53,794 | | $ | 46,212 | |
Natural gas | | 35,256 | | 46,542 | |
NGLs | | 13,885 | | 14,166 | |
| | | | | |
Lease operating expenses (in thousands) | | $ | 19,348 | | $ | 20,852 | |
| | | | | |
Production and ad valorem taxes (in thousands) | | $ | 7,198 | | $ | 9,319 | |
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