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| | | | | | |
QR ENERGY, LP |
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) |
(In thousands) |
| | | | | | |
| | | |
| | | Nine Months Ended |
| | | September 30, 2012 | | | September 30, 2011 |
Cash flows from operating activities: | | | | | | |
Net income | | $ | 46,883 | | $ | 87,604 |
Adjustments to reconcile net income to net cash provided by | | | | | | |
operating activities: | | | | | | |
Depreciation, depletion and amortization | | | 61,428 | | | 58,295 |
Accretion of asset retirement obligations | | | 2,645 | | | 2,033 |
Recognition of unit-based awards | | | 2,124 | | | 990 |
General and administrative expense contributed by affiliates | | | 22,224 | | | 21,252 |
Unrealized gains on derivative contracts | | | (23,011) | | | (135,590) |
Deferred income tax benefit | | | 372 | | | 361 |
Other items | | | 3,222 | | | 1,950 |
Changes in operating assets and liabilities: | | | | | | |
Accounts receivable and other assets | | | (11,232) | | | (16,529) |
Accounts payable and other liabilities | | | 5,731 | | | 2,015 |
Net cash provided by operating activities | | | 110,386 | | | 22,381 |
Cash flows from investing activities: | | | | | | |
Additions to oil and gas properties | | | (80,566) | | | (43,917) |
Proceeds from the sale of oil and gas properties | | | 3,082 | | | 1,327 |
Acquisitions | | | (225,118) | | | - |
Net cash used in investing activities | | | (302,602) | | | (42,590) |
Cash flows from financing activities: | | | | | | |
Proceeds from unit offering, net of offering costs | | | 161,958 | | | 41,963 |
Proceeds from senior note offering, net of discount | | | 295,860 | | | - |
Distributions to the Fund | | | - | | | (42,000) |
Proceeds from issuance of units to the General Partner | | | 115 | | | 715 |
Management incentive fee to the General Partner | | | (3,155) | | | - |
Distributions to unitholders | | | (70,959) | | | (31,223) |
Contributions from the Predecessor | | | - | | | 8,985 |
Proceeds from bank borrowings | | | 116,500 | | | 41,000 |
Repayments on bank borrowings | | | (291,500) | | | - |
Deferred financing costs | | | (8,892) | | | (214) |
Net cash provided by financing activities | | | 199,927 | | | 19,226 |
Increase (decrease) in cash | | | 7,711 | | | (983) |
Cash at beginning of period | | | 17,433 | | | 2,195 |
Cash at end of period | | $ | 25,144 | | $ | 1,212 |
| | | | | | |
See accompanying notes to the consolidated financial statements |
QR Energy, LP
Notes to Consolidated Financial Statements (Unaudited)
Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.
NOTE 1 – ORGANIZATION AND OPERATIONS
QR Energy, LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed on September 20, 2010, to receive certain assets of the affiliated entity, QA Holdings, LP (the “Predecessor”) and own other assets. Certain of the Predecessor’s subsidiaries (collectively known as the “Fund”) include Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC. Quantum Resources Management, LLC (“QRM”) provides management and operational services for us and the Fund. Our general partner is QRE GP, LLC (or “QRE GP”). We conduct our operations through our wholly owned subsidiary QRE Operating, LLC (“OLLC”). Our wholly owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities.
We completed our initial public offering of 15,000,000 common units representing limited partner interests in the Partnership on December 22, 2010 (the “Closing Date”). On the Closing Date, a Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) was executed by and among the Fund, the Partnership and QRE GP with net assets contributed by the Fund. In exchange for the net assets, the Fund received 11,297,737 common and 7,145,866 subordinated limited partner units. QRE GP made a capital contribution to the Partnership in exchange for 35,729 general partner units. The underwriters exercised their over-allotment option in full for 2,250,000 common units issued by the Partnership. Net proceeds from the sale of these common units, after deducting offering costs, were approximately $42 million.
On October 3, 2011, the Fund sold certain oil and gas properties to the Partnership (the “Transferred Properties”) pursuant to a purchase and sale agreement by and among the Fund, the Partnership and OLLC in exchange for 16,666,667 Class C Convertible Preferred Units (“Preferred Units”) and the assumption of $227 million in debt (the “Transaction”). The fair value of the Preferred Units on October 1, 2011 was $21.27 per unit or $354.5 million with net assets of $252.0 million contributed to the Partnership by the Fund. The Transaction was accounted for as a transaction between entities under common control whereby the Transferred Properties were recorded at historical book value. As such, the value of the Preferred Units in excess of the net assets contributed by the Fund was deemed a $102.5 million distribution from the Partnership and allocated pro rata to the general partner and existing limited partners.
On April 17, 2012, we issued 6,202,263 common units representing limited partnership interests in us, and the Fund sold 11,297,737 of its common units it held in us (the “Equity Offering”), to the public pursuant to a registration statement filed with the Securities and Exchange Commission (the “SEC”). In conjunction with the Equity Offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. Refer to Note 10 – Partners’ Capital for further details. Proceeds from the Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.
On April 20, 2012, we closed the acquisition of primarily oil properties from Prize Petroleum, LLC and Prize Petroleum Pipeline, LLC (collectively “Prize”) for approximately $225 million in cash (the “Prize Acquisition”), with an effective date of January 1, 2012. Refer to Note 3 – Acquisitions for further details.
On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register the issuance and sale, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Note 16 – Subsidiary Guarantors for details.
On July 30, 2012, we and our wholly-owned subsidiary QRE FC, issued $300 million of 9.25% Senior Notes (the “Senior Notes”) due 2020. On September 7, 2012, we filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes to exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012. The
exchange of the Senior Notes was completed on November 7, 2012. Refer to Note 9 – Long-Term Debt for further details.
As of September 30, 2012, our ownership structure comprised a 0.1% general partner interest held by QRE GP, a 38.8% limited partner interest held by the Fund, represented by all of our preferred and subordinated units, and a 61.1% limited partner interest held by the public unitholders.
NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles in the United States (“U.S. GAAP”) for complete annual financial statements. During interim periods, the Partnership follows the accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”), filed with the SEC. The unaudited consolidated financial statements for the three and nine months ended September 30, 2012 and 2011 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. Prior period amounts have been revised to conform to current period presentation. Operating results for the three and nine months ended September 30, 2012 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2012. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our 2011 Annual Report.
The Partnership’s historical financial statements previously filed with the SEC have been revised in this quarterly report on Form 10-Q to include the results attributable to the Transferred Properties as if the Partnership owned such assets for all periods presented by the Partnership including the period from January 1, 2011 to September 30, 2011 as the Transaction was between entities under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the Transferred Properties have been prepared from the Predecessor’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. See our accounting policy for transactions between entities under common control set forth in Note 2 of the Notes to Consolidated Financial Statements in our 2011 Annual Report.
Accounting Policy Updates/Revisions
The accounting policies followed by the Partnership are set forth in Note 2 – Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in our 2011 Annual Report. There have been no significant changes to these policies during the nine months ended September 30, 2012 with the exception of the updates below.
Unevaluated Properties
In conjunction with the Prize Acquisition, we acquired unevaluated properties which are not being depleted pending determination of the existence of proved reserves. Unevaluated properties are assessed periodically to ascertain whether there is a probability of obtaining proved reserves in the future. When it is determined that these properties have been promoted to a proved reserve category or there is no longer any probability of obtaining proved reserves from the properties, the costs associated with these properties are transferred into the amortization base to be included in the depletion calculation. Unevaluated properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geological data obtained relating to the properties. Where it is not practical to assess properties individually as their costs are not individually significant, such properties are grouped for purposes of the periodic assessment.
Business Combinations
We account for all business combinations using the purchase method, in accordance with U.S. GAAP. Under the purchase method of accounting, a business combination is accounted for at the purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values. The difference between the fair value of assets acquired and liabilities assumed over the cost of the entity, if any, is recorded as either goodwill or a bargain purchase gain. The Partnership has not recognized any goodwill from business combinations.
Recent 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 IFRSs (ASU 2011-04). The amendments in ASU 2011-04 are the result of the FASB's and the International Accounting Standards Board's (“IASB”) work to develop common requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP and the International Financial Reporting Standards (“IFRS”). ASU 2011-04 explains how to measure fair value and changes the wording used to describe many of the fair value requirements in GAAP, but does not require additional fair value measurements. This guidance becomes effective for interim and annual periods beginning on or after December 15, 2011, with early adoption prohibited. This amendment was adopted by us on January 1, 2012 and did not have a material impact on our financial position, results of operations or cash flows.
In December 2011, the FASB issued ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). The objective of this update is to provide enhanced disclosures that will enable the users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The amendment will require entities to disclose both gross information and net information about instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. This scope would include financial and derivative instruments that either offset in accordance with U.S. GAAP or are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with U.S. GAAP. This amendment becomes effective for annual reporting periods beginning on or after January 1, 2013, and the interim periods within those annual periods. We are evaluating the potential impacts this ASU will have on our disclosures.
NOTE 3 – ACQUISITIONS
Prize Properties
On April 20, 2012 we closed the Prize Acquisition. We acquired predominantly low decline, long life oil properties, almost all of which are located in the Ark-La-Tex area, for $225 million in cash after customary purchase price adjustments. The acquired properties had estimated proved reserves as of December 31, 2011 utilizing SEC case pricing of 13.3 MMBoe. The acquisition had an effective date of January 1, 2012.
The Prize Acquisition qualified as a business combination and was accounted for under the purchase method of accounting. Effective April 20, 2012 the results of operations of the acquired Prize assets are included in our unaudited statement of operations for the three and nine months ended September 30, 2012. Accordingly, we recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. The fair value measurements of the oil and gas properties and asset retirement obligations were measured using valuation techniques and inputs that convert future cash flows to a single discounted amount.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisition closing date (in thousands):
| | | |
| | | |
Oil and gas properties | | | |
Evaluated | | $ | 223,740 |
Unevaluated | | | 9,000 |
Asset retirement obligation | | | (4,738) |
Environmental liability | | | (1,891) |
Other current liabilities | | | (993) |
Net assets acquired | | $ | 225,118 |
| | | |
The above estimated fair values of assets acquired and liabilities assumed are provisional and are based on the information that was available as of the acquisition date to estimate the fair value of assets acquired and liabilities assumed. We believe that the information provides a reasonable basis for estimating the fair values of assets acquired and liabilities assumed. We expect to finalize the valuation and complete the purchase price allocation as soon as practicable but no later than one year from the acquisition date.
The costs associated with the Prize Acquisition of $1.0 million are recorded in the acquisition and transaction costs caption of the consolidated statement of operations for nine months ended September 30, 2012. In conjunction with the Prize Acquisition, we assumed an estimated environmental liability of $1.9 million. Refer to Note 11 – Commitments And Contingencies for further details.
Since the closing date, revenues of $8.7 million and $15.2 million and operating expenses of $3.4 million and $6.1 million related to the operation of the Prize properties are included in the consolidated statements of operations for the three and nine months ended September 30, 2012. The following unaudited consolidated income statement information provide unaudited actual results for the three months ended September 30, 2012 and pro forma income statement information for the nine months ended September 30, 2012 and for the three and nine months ended September 30, 2011, which assumes the Prize Acquisition had occurred on January 1, 2011. The unaudited pro forma results reflect certain adjustments related to the acquisition, such as increased depreciation and amortization expense on the assets acquired from Prize resulting from the fair value of assets acquired. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisition been completed at the beginning of the periods presented, nor are they indicative of future results of operations.
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| | | Three Months Ended | | | Nine Months Ended |
| | | (Unaudited) | | | (Unaudited) |
| | | September 30, 2012 | | | September 30, 2011 | | | September 30, 2012 | | | September 30, 2011 |
| | | Actual | | | Pro Forma | | | Pro Forma | | | Pro Forma |
Total Revenue | | $ | 64,969 | | $ | 72,815 | | $ | 205,081 | | $ | 221,574 |
Operating income | | $ | 8,565 | | $ | 14,292 | | $ | 33,314 | | $ | 58,349 |
Net income (loss) | | $ | (45,007) | | $ | 107,530 | | $ | 51,983 | | $ | 97,577 |
Net income (loss) per unit: | | | | | | | | | | | | |
Common unitholders' (basic) | | $ | (1.25) | | $ | 1.21 | | $ | 0.54 | | $ | 1.08 |
Common unitholders' (diluted) | | $ | (1.25) | | $ | 1.21 | | $ | 0.54 | | $ | 1.08 |
Subordinated units (basic) | | $ | (1.26) | | $ | 1.21 | | $ | 0.53 | | $ | 1.08 |
Subordinated units (diluted) | | $ | (1.26) | | $ | 1.21 | | $ | 0.53 | | $ | 1.08 |
On October 26, 2012, we entered into a purchase and sale agreement with a private seller to purchase predominantly oil and natural gas properties in the Ark-La-Tex area for approximately $215 million. Refer to Note 17 – Subsequent Events for further details.
NOTE 4 – FAIR VALUE MEASURMENTS
Our financial instruments, including cash, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Our financial and non-financial assets and liabilities that are being measured on a recurring basis are measured and reported at fair value.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). U.S. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:
Level 1 – Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2 – Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.
Level 3 – Defined as unobservable inputs for use when little or no market data exists, therefore requires an entity to develop its own assumptions for the asset or liability.
Commodity Derivative Instruments — The fair value of the commodity derivative instruments is estimated using a combined income and market valuation methodology based upon observable forward commodity price and volatility curves. The curves are obtained from independent pricing services. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.
Interest Rate Derivative Instruments — The fair value of the interest rate derivative instruments is estimated using a combined income and market valuation methodology based upon observable forward interest rates and volatility curves. The curves are obtained from independent pricing services. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.
We utilize the most observable inputs available for the valuation technique utilized. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table sets forth, by level within the hierarchy, the fair value of our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2012 and December 31, 2011. All fair values reflected below and on the consolidated balance sheet have been adjusted for nonperformance risk.
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As of September 30, 2012 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 |
Assets from commodity derivative instruments | | $ | 123,932 | | $ | - | | $ | 123,932 | | $ | - |
| | $ | 123,932 | | $ | - | | $ | 123,932 | | $ | - |
| | | | | | | | | | | | |
Liabilities from commodity derivative instruments | | $ | 6,062 | | $ | - | | $ | 6,062 | | $ | - |
Liabilities from interest rate derivative instruments | | | 13,270 | | | - | | | 13,270 | | | - |
| | $ | 19,332 | | $ | - | | $ | 19,332 | | $ | - |
| | | | | | | | | | | | |
As of December 31, 2011 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 |
Assets from commodity derivative instruments | | $ | 103,233 | | $ | - | | $ | 103,233 | | $ | - |
Assets from interest rate derivative instruments | | | 20 | | | - | | | 20 | | | - |
| | $ | 103,253 | | $ | - | | $ | 103,253 | | $ | - |
| | | | | | | | | | | | |
Liabilities from commodity derivative instruments | | $ | 2,502 | | $ | - | | $ | 2,502 | | $ | - |
Liabilities from interest rate derivative instruments | | | 23,973 | | | - | | | 23,973 | | | - |
| | $ | 26,475 | | $ | - | | $ | 26,475 | | $ | - |
Fair Value of Other Financial Instruments
Fair value guidance requires certain fair value disclosures, such as those on our long-term debt, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.
Revolving Credit Facility — The fair value of our long term debt depends primarily on the current active market LIBOR. The carrying value of our long term debt as of September 30, 2012 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.
Derivative Premiums – The fair value of the deferred premiums on our commodity derivatives is based on the current active market LIBOR. The carrying value of the premiums as of September 30, 2012 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy. Refer to Note 5 – Derivative Activities for further information on the derivative premiums.
Senior Notes – The fair value of the Senior Notes is measured based on inputs from quoted, unadjusted prices from over-the-counter markets for debt instruments. If the Senior Notes had been measured at fair value, we would classify them as Level 1 under the fair value hierarchy. The fair value of the Senior Notes as of September 30, 2012 was $304.9 million.
There have been no transfers between levels within the fair value measurement hierarchy during the nine months ended September 30, 2012.
NOTE 5 – DERIVATIVE ACTIVITIES
We have elected not to designate any of our derivatives as hedging instruments. As a result, these derivative instruments are marked to market at the end of each reporting period, and changes in the fair value of the derivatives are recorded as gains or losses in the consolidated statements of operations.
Although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have presented all asset and liability positions without netting. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We do not post collateral under any of these contracts as they are secured under our credit facility.
Commodity Derivatives
Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. As such, future earnings are subject to fluctuations due to changes in the market price of oil and natural gas. We use derivatives to reduce our exposure to changes in the prices of oil and natural gas. Our policies do not permit the use of derivatives for speculative purposes.
During the nine months ended September 30, 2012, we entered into new oil swap contracts with settlement dates ranging from 2012 through 2017, natural gas put contracts, with deferred premiums, and swap contracts with settlement dates ranging from 2015 through 2017. All of the new contracts were entered into with the same counterparties as our existing contracts.
The deferred premiums associated with certain of our oil and natural gas derivative instruments are $4.9 million and are classified as other non-current liabilities on the consolidated balance sheet as of September 30, 2012. There were no deferred derivative contract premiums at December 31, 2011. These deferred premiums will be paid to the counterparty with each monthly settlement (January 2015 – December 2017) and recognized as an adjustment of realized gain (loss) on derivative instruments.
We hold commodity derivative contracts to manage our exposure to changes in the price of oil and natural gas related to our oil and natural gas production. As of September 30, 2012, the notional volumes of our commodity derivative contracts were:
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Commodity | | | Index | | | Oct 1 - Dec 31, 2012 | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 |
Oil positions: | | | | | | | | | | | | | | | | | | | | | |
Swaps | | | | | | | | | | | | | | | | | | | | | |
Hedged Volume (Bbls/d) | | | WTI | | | 5,872 | | | 6,543 | | | 5,661 | | | 4,540 | | | 2,480 | | | 3,730 |
Average price ($/Bbls) | | | | | $ | 100.34 | | $ | 99.75 | | $ | 97.91 | | $ | 96.87 | | $ | 92.07 | | $ | 87.57 |
Collars | | | | | | | | | | | | | | | | | | | | | |
Hedged Volume (Bbls/d) | | | WTI | | | | | | | | | 425 | | | 1,025 | | | 1,500 | | | |
Average floor price ($/Bbls) | | | | | | | | | | | $ | 90.00 | | $ | 90.00 | | $ | 80.00 | | | |
Average ceiling price ($/Bbls) | | | | | | | | | | | $ | 106.50 | | $ | 110.00 | | $ | 102.00 | | | |
| | | | | | | | | | | | | | | | | | | | | |
Natural gas positions: | | | | | | | | | | | | | | | | | | | | | |
Swaps | | | | | | | | | | | | | | | | | | | | | |
Hedged Volume (MMBtu/d) | | | Henry Hub | | | 30,213 | | | 29,674 | | | 25,907 | | | 6,520 | | | 11,350 | | | 10,445 |
Average price ($/MMBtu) | | | | | $ | 5.89 | | $ | 6.07 | | $ | 6.23 | | $ | 5.43 | | $ | 4.27 | | $ | 4.47 |
Basis Swaps | | | | | | | | | | | | | | | | | | | | | |
Hedged Volume (MMBtu/d) | | | Henry Hub | | | 20,709 | | | 18,466 | | | 17,066 | | | 14,400 | | | | | | |
Average price ($/MMBtu) | | | | | $ | (0.15) | | $ | (0.17) | | $ | (0.19) | | $ | (0.19) | | | | | | |
Collars | | | | | | | | | | | | | | | | | | | | | |
Hedged Volume (MMBtu/d) | | | Henry Hub | | | 2,609 | | | 2,466 | | | 4,966 | | | 18,000 | | | | | | |
Average floor price ($/MMBtu) | | | | | $ | 6.50 | | $ | 6.50 | | $ | 5.74 | | $ | 5.00 | | | | | | |
Average ceiling price ($/MMBtu) | | | | | $ | 8.60 | | $ | 8.65 | | $ | 7.51 | | $ | 7.48 | | | | | | |
Puts | | | | | | | | | | | | | | | | | | | | | |
Hedged Volume (MMBtu/d) | | | Henry Hub | | | | | | | | | | | | 420 | | | 11,350 | | | 10,445 |
Average price ($/MMBtu) | | | | | | | | | | | | | | $ | 4.00 | | $ | 4.00 | | $ | 4.00 |
Interest Rate Derivatives
In an effort to mitigate exposure to changes in market interest rates, we have entered into interest rate swaps that effectively fix the LIBOR component on our outstanding variable rate debt. The changes in the fair value of these instruments are recorded in current earnings.
On July 31, 2012, we terminated certain interest rate derivative contracts which were scheduled to expire at various times through the fourth quarter 2015 and recorded a $15 million realized loss for the early termination.
The fair value of our derivatives as recorded on our balance sheet was as follows as of the dates indicated:
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| | | | | | | | | | | | |
| | | September 30, 2012 | | | December 31, 2011 |
| | | Asset | | | Liability | | | Asset | | | Liability |
| | | Derivatives | | | Derivatives | | | Derivatives | | | Derivatives |
Commodity contracts | | $ | 123,932 | | $ | 6,062 | | $ | 103,233 | | $ | 2,502 |
Interest rate contracts | | | - | | | 13,270 | | | 20 | | | 23,973 |
| | $ | 123,932 | | $ | 19,332 | | $ | 103,253 | | $ | 26,475 |
| | | | | | | | | | | | |
Commodity | | | | | | | | | | | | |
Current | | $ | 42,482 | | $ | 565 | | $ | 32,683 | | $ | 1,284 |
Noncurrent | | | 81,450 | | | 5,497 | | | 70,550 | | | 1,218 |
| | $ | 123,932 | | $ | 6,062 | | $ | 103,233 | | $ | 2,502 |
Interest | | | | | | | | | | | | |
Current | | $ | - | | $ | 4,611 | | $ | - | | $ | 8,285 |
Noncurrent | | | - | | | 8,659 | | | 20 | | | 15,688 |
| | $ | - | | $ | 13,270 | | $ | 20 | | $ | 23,973 |
| | | | | | | | | | | | |
Total Derivatives | | | | | | | | | | | | |
Current | | $ | 42,482 | | $ | 5,176 | | $ | 32,683 | | $ | 9,569 |
Noncurrent | | | 81,450 | | | 14,156 | | | 70,570 | | | 16,906 |
| | $ | 123,932 | | $ | 19,332 | | $ | 103,253 | | $ | 26,475 |
The following table presents the impact of derivatives and their location within our unaudited consolidated statements of operations for the three and nine months ended September 30, 2012 and September 30, 2011:
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| | | Three Months Ended | | | Nine Months Ended |
| | | September 30, 2012 | | | September 30, 2011 | | | September 30, 2012 | | | September 30, 2011 |
Realized gains (losses): | | | | | | | | | | | | |
Commodity contracts (1) | | $ | 13,375 | | $ | (39,072) | | $ | 35,668 | | $ | (79,924) |
Interest rate swaps (2) | | | (16,145) | | | (969) | | | (20,775) | | | (2,231) |
Total | | $ | (2,770) | | $ | (40,041) | | $ | 14,893 | | $ | (82,155) |
| | | | | | | | | | | | |
Unrealized gains (losses): | | | | | | | | | | | | |
Commodity contracts (1) | | $ | (55,585) | | $ | 153,378 | | $ | 12,328 | | $ | 160,233 |
Interest rate swaps (2) | | | 12,973 | | | (14,596) | | | 10,683 | | | (24,643) |
Total | | $ | (42,612) | | $ | 138,782 | | $ | 23,011 | | $ | 135,590 |
| | | | | | | | | | | | |
Total gains (losses): | | | | | | | | | | | | |
Commodity contracts (1) | | $ | (42,210) | | $ | 114,306 | | $ | 47,996 | | $ | 80,309 |
Interest rate swaps (2) | | | (3,172) | | | (15,565) | | | (10,092) | | | (26,874) |
Total | | $ | (45,382) | | $ | 98,741 | | $ | 37,904 | | $ | 53,435 |
(1) Gain (loss) on commodity derivative contracts is located in other income (expense) in the consolidated statements of operations.
(2) Gain (loss) on interest rate derivatives contracts is recorded as part of interest expense and is located in other income (expense) in the consolidated statements of operations.
NOTE 6 – INCOME TAXES
We do not pay federal income taxes as our profits or losses are reported to the taxing authorities by the individual partners.
Our income taxes are entirely attributable to the Texas Margin Tax which is derived from our taxable income apportioned to Texas. We recorded a deferred tax asset of $0.3 million and $0.3 million related to its operations located in Texas as of September 30, 2012 and December 31, 2011 and a deferred tax liability of $0.4 million and less than $0.1 million as of September 30, 2012 and December 31, 2011. The deferred tax asset and deferred tax liability are presented net as a deferred tax liability of $0.1 million on the consolidated balance sheet as of September 30, 2012 and as a deferred tax asset of $0.3 million on the consolidated balance sheet as of December 31, 2011. Our provision for income taxes was a net benefit of $0.2 million and a net expense of $0.5 million for the three and nine months ended September 30, 2012 and a net expense of $0.8 million and $0.9 million for the three and nine months ended September 30, 2011.
NOTE 7 – ASSET RETIREMENT OBLIGATIONS
We record the asset retirement obligation (“ARO”) liability on our unaudited consolidated balance sheet and capitalize the cost in the “Oil and gas properties, using the full cost method of accounting” balance sheet caption during the period in which the obligation is incurred. We record the accretion of our ARO liabilities in “Accretion of asset retirement obligations” expense in our unaudited consolidated statements of operations. Payments to settle asset retirement obligations occur over the lives of the oil and gas properties. Revisions during the reporting period were due to changes in cost estimates for wells currently being retired.
Changes in our asset retirement obligations for nine months ended September 30, 2012 are presented in the following table:
| | | |
| | | |
| | | Nine Months Ended |
| | | September 30, 2012 |
Beginning of period | | $ | 65,701 |
Assumed in acquisition | | | 4,738 |
Divested | | | (23) |
Revisions to previous estimates | | | 2,928 |
Liabilities incurred | | | 1,208 |
Liabilities settled | | | (2,845) |
Accretion expense | | | 2,645 |
End of period | | $ | 74,352 |
Less: Current portion of asset retirement obligations | | | (845) |
Asset retirement obligations - non-current | | $ | 73,507 |
| | | |
NOTE 8 – ACCRUED AND OTHER LIABILITIES
As of September 30, 2012 and December 31, 2011, we had the following accrued and other liabilities:
| | | | | | |
| | | | | | |
| | | September 30, 2012 | | | December 31, 2011 |
Distributions payable | | $ | 25,628 | | $ | 20,545 |
Accrued capital spending | | | 2,931 | | | 9,591 |
Production expense accrual | | | 16,925 | | | 12,872 |
Senior notes interest accrual | | | 4,625 | | | - |
Management incentive fee | | | 4,538 | | | 1,572 |
Other | | | 5,535 | | | 5,447 |
| | $ | 60,182 | | $ | 50,027 |
NOTE 9 – LONG-TERM DEBT
As of September 30, 2012 and December 31, 2011, long-term consisted of (in thousands):
| | | | | | |
| | | September 30, 2012 | | | December 31, 2011 |
Senior revolving credit facility | | $ | 325,000 | | $ | 500,000 |
9.25% Senior Notes due 2020 (1) | | | 295,946 | | | - |
Total long-term debt | | $ | 620,946 | | $ | 500,000 |
(1) The amount is net of unamortized discount of $4.1 million as of September 30, 2012.
Revolving Credit Facility
On December 22, 2010, the Partnership entered into a Credit Agreement along with QRE GP, OLLC as Borrower, and a syndicate of banks (the “Credit Agreement”).
We entered into a Second Amendment to the Credit Agreement on March 16, 2012 to provide for additional derivative contracts to cover production of proved reserves to be acquired.
In April 2012, we entered into the Third Amendment to the Credit Agreement whereby increasing our credit facility from $750 million to $1.5 billion, increasing our borrowing base from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017. The Third Amendment became effective upon the closing of the Prize Acquisition.
As a result of the issuance of the Senior Notes on July 30, 2012, our borrowing base was reduced by $75 million to $655 million from $730 million. On the same date, we made a payment on our outstanding borrowings under our revolving credit facility of $291.5 million using the cash proceeds from the Senior Notes issuance and cash on hand. In connection with the reduction of the borrowing base, we wrote-off approximately $0.7 million of deferred loan costs associated with the Credit Agreement. On October 30, 2012, we were notified of an increase in our borrowing base, as part of our semi-annual borrowing base redetermination, from $655 million to the borrowing base prior to the issuance of the Senior Notes of $730 million.
As of September 30, 2012, we had $325.0 million of borrowings outstanding and $0.1 million of letters of credit outstanding resulting in $329.9 million of borrowing availability. As of December 31, 2011, we had $500.0 million of borrowings and $0.4 million letters of credit outstanding resulting in $129.6 million of borrowing availability.
As of November 8, 2012 we had $325.0 million of borrowings outstanding under our revolving credit facility and $404.9 million of borrowing availability.
As of September 30, 2012, the Credit Agreement provides for a five-year, $1.5 billion revolving credit facility maturing on April 20, 2017, with a borrowing base of approximately $655 million. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ pricing assumptions, and other various factors unique to each member bank. The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% 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 1.50% to 2.50% 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.
The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our 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; prepay certain indebtedness; and also requires us to provide audited financial statements within 90 days of year end and quarterly unaudited
financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of September 30, 2012, we were in compliance with all of the Credit Agreement covenants.
Bridge Loan Commitment
In conjunction with the Prize Acquisition, we entered into a secured commitment (the “Bridge Loan Commitment”) to provide an additional $200 million of bank loans to fund the acquisition as needed. We did not utilize any borrowings under the commitment and as of May 10, 2012 the Bridge Loan Commitment was terminated by us. We incurred $1.6 million of commitment fees related to the Bridge Loan Commitment which is recorded in interest expense for the nine months ended September 30, 2012.
9.25% Senior Notes
On July 30, 2012, we and our wholly-owned subsidiary QRE FC, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 9.25% Senior Notes, due 2020. The Senior Notes were issued at 98.62% of par. We received approximately $291.2 million of cash proceeds, net of the discount and underwriting fees, with total net proceeds of approximately $290.2 million, after $1.0 million of offering costs. We used the net proceeds from the sale of the Senior Notes to repay borrowings outstanding under our credit facility. We will have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Our and QRE FC’s obligations under the Senior Notes are guaranteed by OLLC. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor’s, other, debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Note 16 – Subsidiary Guarantors for further details of our guarantors.
The indenture governing the Senior Notes (the “Indenture”) restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale-leaseback transactions; (ii) pay distributions on, or repurchase, equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants. The Indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the Senior Notes.
On September 7, 2012, we filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes to exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012. The exchange offer was completed on November 7, 2012.
NOTE 10 — PARTNERS’ CAPITAL
Units Outstanding
The table below details the units outstanding as of September 30, 2012 and December 31, 2011, and the changes in outstanding units for the nine months ended September 30, 2012. As of September 30, 2012, the Fund owned all preferred units and all subordinated units.
| | | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | Preferred Units | | | General Partner | | | Public Common | | | Affiliated Common | | | Subordinated |
Balance - December 31, 2011 | | | 16,666,667 | | | 35,729 | | | 17,292,279 | | | 11,297,737 | | | 7,145,866 |
Vested units awarded under our Long Term Incentive | | | | | | | | | | | | | | | |
Performance Plan | | | - | | | - | | | 18,359 | | | - | | | - |
Reduction in units to cover individuals' tax withholdings | | | - | | | - | | | (918) | | | - | | | - |
Issuance of units to General Partner | | | - | | | 6,018 | | | - | | | - | | | - |
Affiliated unit sale to the public | | | - | | | - | | | 11,297,737 | | | (11,297,737) | | | - |
Unit offering | | | - | | | - | | | 8,827,263 | | | - | | | - |
Balance - September 30, 2012 | | | 16,666,667 | | | 41,747 | | | 37,434,720 | | | - | | | 7,145,866 |
On April 17, 2012, we issued 6,202,263 common units representing limited partnership interests in us, and the Fund sold 11,297,737 of its common units it held in us to the public pursuant to a registration statement filed with the SEC. In conjunction with the Equity Offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. Proceeds from the Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.
On April 25, 2012, QRE GP purchased 6,018 general partner units in order to maintain its 0.1% ownership percentage in us. The units were purchased at a price of $19.18 per unit.
On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Note 16 – Subsidiary Guarantors for details
Allocations of Net Income (Loss)
Net income (loss) is allocated to the preferred unitholders to the extent distributions are made or accrued to them during the period, to QRE GP to the extent of the management incentive fee, with the remaining income being allocated between QRE GP and the common and subordinated unitholders in proportion to their pro rata ownership during the period.
Cash Distributions
We intend to continue to make regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our Credit Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in our Credit Agreement, occurs or would result from the cash distribution.
Our partnership agreement, as amended, requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. We intend to fund a portion of our capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to 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 pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.
As of September 30, 2012, QRE GP owns a 0.1% general partner interest in us, represented by 41,747 general partner units. QRE GP has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. QRE GP’s 0.1% interest in these distributions will be reduced if we
issue additional units in the future and QRE GP does not contribute a proportionate share of capital to us to maintain its 0.1% general partnership interest.
Our partnership agreement, as amended, requires that within 45 days after the end of each quarter, we distribute all of our available cash to preferred unitholders, in arrears, and common unitholders of record on the applicable record date, as determined by QRE GP.
Distribution activities are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Limited Partners | | | | | | |
| | | | | | | | | | | | | | | | | | Affiliated | | | | | | |
Payment Date | | | For the period ended | | | Distributions to Preferred Unitholders | | | Distributions per Preferred Unit(1) | | | General Partner | | | Public Common | | | Common | | | Subordinated | | | Total Distributions to Other Unitholders | | | Distributions per other units |
(In thousands, except per unit amounts) |
February 10, 2012 | | | December 31, 2011 | | | 3,424 | | $ | 0.2054 | | | 16 | | | 8,344 | | | 5,368 | | | 3,393 | | | 17,121 | | | 0.4750 |
May 11, 2012 | | | March 31, 2012 | | | 3,500 | | $ | 0.21 | | | 20 | | | 17,892 | | | - | | | 3,394 | | | 21,306 | | | 0.4750 |
August 10, 2012 | | | June 30, 2012 | | | 3,500 | | $ | 0.21 | | | 20 | | | 18,584 | | | - | | | 3,484 | | | 22,088 | | | 0.4875 |
November 9, 2012 | | | September 30, 2012 | | | 3,500 | | $ | 0.21 | | | 20 | | | 18,624 | | | - | | | 3,484 | | | 22,128 | | | 0.4875 |
(1) Preferred units paid in February 2012 were prorated a quarterly distribution for the portion of the fourth quarter beginning on October 3, 2011 through December 31, 2011 in accordance with the Partnership Agreement.
On September 28, 2012, the board of directors of QRE GP declared a $0.4875 per unit cash distribution for the third quarter 2012 which is payable on November 9, 2012 to unitholders of record at the close of business on October 29, 2012. The aggregate amount of the third quarter common and preferred unit holder distribution accrued, as of September 30, 2012, was $25.6 million.
NOTE 11 – COMMITMENTS AND CONTINGENCIES
Services Agreement
We have entered into a services agreement (the “Services Agreement”) with QRM as described in Note 14 – Related Party Transactions, under which QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined under the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee. The Partnership had no other commitments as of September 30, 2012.
Legal Proceedings
In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We currently have no legal proceedings with a probable adverse outcome. Therefore, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
Environmental Contingencies
As of September 30, 2012, we have approximately $1.9 million in environmental liabilities related to the Prize Acquisition. This is management’s best estimate of the costs for remediation and restoration with respect to these environmental matters, although the ultimate cost could increase materially. The environmental liability is recorded in the other liabilities caption on the consolidated balance sheet. Inherent uncertainties exist in these estimates primarily due to unknown conditions, changing governmental regulation and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration.
NOTE 12 – NET INCOME/(LOSS) PER LIMITED PARTNER UNIT
The following sets forth the calculation of net income (loss) per limited partner unit for the three and nine months ended September 30, 2012 and September 30, 2011:
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Three Months Ended | | | Nine Months Ended |
| | | September 30, 2012 | | | September 30, 2011 | | | September 30, 2012 | | | September 30, 2011 |
Net income (loss) | | $ | (45,007) | | $ | 105,165 | | $ | 46,883 | | $ | 87,604 |
Net income (loss) attributable to predecessor operations | | | - | | | (53,235) | | | - | | | (49,091) |
Distribution on Class C convertible preferred units | | | (3,500) | | | - | | | (10,500) | | | - |
Amortization of preferred unit discount | | | (3,751) | | | - | | | (11,140) | | | - |
Net income (loss) available to other unitholders | | | (52,258) | | | 51,930 | | | 25,243 | | | 38,513 |
Less: general partner's interest in net income (loss) | | | 3,705 | | | 52 | | | 6,150 | | | 39 |
Limited partners' interest in net income (loss) | | $ | (55,963) | | $ | 51,878 | | $ | 19,093 | | $ | 38,474 |
Common unitholders' interest in net income (loss) | | $ | (46,930) | | $ | 41,540 | | $ | 16,717 | | $ | 30,829 |
Subordinated unitholders' interest in net income (loss) | | $ | (9,033) | | $ | 10,338 | | $ | 2,376 | | $ | 7,644 |
Net loss per limited partner unit: | | | | | | | | | | | | |
Common unitholders' (basic) | | $ | (1.25) | | $ | 1.45 | | $ | 0.49 | | $ | 1.07 |
Common unitholders' (diluted) | | | (1.25) | | | 1.45 | | | 0.49 | | | 1.07 |
Subordinated unitholders' (basic) | | $ | (1.26) | | $ | 1.45 | | $ | 0.33 | | $ | 1.07 |
Subordinated unitholders' (diluted) | | | (1.26) | | | 1.45 | | | 0.33 | | | 1.07 |
Weighted average number of limited partner units outstanding (1): | | | | | | | | | | | | |
Common units (basic) | | | 37,425 | | | 28,713 | | | 34,347 | | | 28,698 |
Common units (diluted) | | | 37,425 | | | 28,713 | | | 34,347 | | | 28,698 |
Subordinated units (basic and diluted) | | | 7,146 | | | 7,146 | | | 7,146 | | | 7,146 |
| (1) | For the three and nine months ended September 30, 2012, we had weighted average preferred units outstanding of 16,666,667, which are contingently convertible. These units could potentially dilute earnings per unit in the future and have not been included in the earnings per unit calculation for the three and nine months ended September 30, 2012, as they were anti-dilutive for the periods. |
Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the limited partner unitholders, after deducting QRE GP’s 0.1% interest in net income (loss), by the weighted average number of limited partner units outstanding during the three and nine months ended September 30, 2012. We had 37,434,720 common units and 7,145,866 subordinated units outstanding as of September 30, 2012.
NOTE 13 – UNIT-BASED COMPENSATION
The QRE GP, LLC Long-Term Incentive Plan (the “Plan”) was established for employees, officers, consultants and directors and consultants of QRE GP and its affiliates, including QRM, who perform services for us. The Plan consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the Plan is to provide additional incentive compensation to employees providing services to us and to align the economic interests of such employees with the interests of our unitholders. The Plan limits the number of common units that may be delivered pursuant to awards under the Plan to 1.8 million units.
Restricted Units
During 2012, we issued restricted stock units with a service condition (“Restricted Units”) and restricted units with a performance condition (“Performance Units”). The fair value of the restricted units is based on the closing price of our common units at the grant date.
Service Restricted Units
For Restricted Units, we recognize compensation expense using a straight-line amortization of the grant date fair value over the vesting period of the award. On July 25, 2012, we granted an additional 392,149 Restricted Units to employees of QRM with a grant date per unit value of $18.19. For the three and nine months ended September 30, 2012, we recognized compensation expense related to the outstanding awards of $1.4 million and $2.2 million. For the three and nine months ended September 30, 2011 we recognized compensation expense of $0.4 million and $1.0 million. As of September 30, 2012, we had 645,563 of Restricted Units outstanding with unrecognized grant
date fair value compensation expense of $11.9 million, which we expect to be recognized over a weighted-average period of approximately 3 years.
Performance Restricted Units.
In July 2012, we granted a target number of performance shares under a performance unit award agreement to members of our senior management. The performance awards will be earned over a three year period based on the Partnership’s performance relative to its peers, with details to be determined and approved by our board in accordance with the Plan.
At each reporting period, we will assess the probability of meeting the performance conditions to determine the final units to be issued for each Performance Unit and estimate compensation expense based on this probability. For the three and nine months ended September 30, 2012, we recognized compensation expense related to the Performance Units on a straight-line method within the Restricted Units until the performance conditions are approved. There were no Performance Units outstanding in 2011.
The following table summarizes our restricted unit-based awards for nine months ended September 30, 2012:
| | | | | | | | | | | |
| | | | | Weighted | | | | Weighted |
| | | | | Average | | | | Average |
| | | Number of | | Grant-Date | | Number of | | Grant-Date |
| | | Service Restricted units | | Fair Value | | Performance units | | Fair Value |
Unvested units, December 31, 2011 | | | 271 | | $ | 20.33 | | - | | $ | - |
Granted | | | 428 | | | 18.18 | | 121 | | | 18.06 |
Forfeited | | | (35) | | | 20.23 | | - | | | - |
Vested | | | (18) | | | 20.16 | | - | | | - |
Unvested units, September 30, 2012 | | | 646 | | $ | 18.80 | | 121 | | $ | 18.06 |
| | | | | | | | | | | |
Note 14 – RELATED PARTY TRANSACTIONS
Ownership in QRE GP by the Management of the Fund and its Affiliates
As of September 30, 2012, affiliates of the Fund owned 100% of QRE GP, an aggregate 38.8% limited partner interest in us represented by all of our preferred and subordinated units. In addition, QRE GP owned a 0.1% general partner interest in us, represented by 41,747 general partner units.
Contracts with QRE GP and its Affiliates
We have entered into agreements with QRE GP and its affiliates. The following is a description of the activity of those agreements.
Services Agreement
Under the Services Agreement, until December 31, 2012, QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined under the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee. For the three and nine months ended September 30, 2012 we were charged $1.8 million and $5.4 million and for the three and nine months ended September 30, 2011, we were charged $0.7 million and $0.8 million in administrative services fees in accordance with the Services Agreement. We will reimburse QRE GP for such payments it makes to QRM.
Beginning on January 1, 2013, QRM will be entitled to a quarterly administrative services fee based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. The fee will include direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If the Fund raises a second fund, the quarterly administrative services costs will be further divided to include the second fund as well. The allocation methodology was developed with the assistance of a third-party consultant with extensive experience in this area. These fees will be included in general and administrative expenses in our consolidated statement of operations. QRM will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.
In connection with the management of our business, QRM provides services for invoicing and collection of our revenues as well as processing of payments to our vendors. Periodically QRM remits cash to us for the net working capital received on our behalf. Changes in the affiliate receivable balances during nine months ended September 30, 2012 from the year ended December 31, 2011 are included below:
| | | |
| | | |
Net affiliate receivable as of December 31, 2011 | | | 3,734 |
Revenues and other increases | | | 187,036 |
Expenditures | | | (155,351) |
Settlements from the Fund | | | (26,100) |
Net affiliate receivable as of September 30, 2012 | | $ | 9,319 |
Other Contributions to Partners’ Capital
Other contributions to partners’ capital for the nine months ended September 30, 2012 include non-cash general and administrative expense of $22.2 million contributed by the Fund, which represents our share of allocable general and administrative expenses incurred by QRM on our behalf but not reimbursable by us.
Management Incentive Fee
Under our partnership agreement, for each quarter for which we have paid distributions that equaled or exceeded 115% of our minimum quarterly distribution (which amount we refer to as our “Target Distribution”), or $0.4744 per unit, QRE GP will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of our management incentive fee base, which will be an amount equal to the sum of:
| · | The future net revenue of our estimated proved oil and natural gas reserves, discounted to present value at 10% per annum and calculated based on SEC methodology, |
| · | Adjusted for our commodity derivative contracts; and |
| · | The fair market value of our assets, other than our estimated oil and natural gas reserves and our commodity derivative contracts that principally produce qualifying income for federal income tax purposes, at such value as may be determined by the board of directors of QRE GP and approved by the conflicts committee of QRE GP’s board of directors. |
For the nine months ended September 30, 2012, the management incentive fee earned by QRE GP was $6.1 million. For the nine months ended September 30, 2011, no management incentive fee was earned by or paid to our general partner.
Lease Guarantees
The Fund has entered into various lease contracts that can routinely extend beyond five years which list the Partnership as a guarantor.
Long–Term Incentive Plan
The Plan provides compensation to employees, officers, consultants and directors of QRE GP and those of its affiliates, including QRM, who perform services for us. As of September 30, 2012 and December 31, 2011, 766,700 and 271,364 restricted units with a grant date fair value of $14.4 million and $5.5 million were outstanding under the Plan. For additional discussion regarding the Plan see Note 13 – Unit-Based Compensation.
Distributions of Available Cash to QRE GP and Affiliates
We generally make cash distributions to our common and subordinated unitholders pro rata, including QRE GP and its affiliates. The Partnership paid a cash distribution on May 11, 2012 and August 31, 2012 for the quarters ended March 31, 2012 and June 30, 2012 and declared a third quarter 2012 distribution payable on November 9, 2012. Refer to Note 10 – Partners’ Capital for details on the distributions.
Our Relationship with Bank of America
Don Powell, one of our independent directors, is also an independent director of Bank of America (“BOA”). BOA is a lender under our Credit Agreement.
NOTE 15 – SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow information was as follows for the periods indicated:
| | | | | | |
| | | | | | |
| | | Nine Months Ended |
| | | September 30, 2012 | | | September 30, 2011 |
Supplemental Cash Flow Information | | | | | | |
Cash paid during the period for interest | | $ | 33,322 | | $ | 13,236 |
Non-cash Investing and Financing Activities | | | | | | |
Change in accrued capital expenditures | | | (6,660) | | | 2,165 |
Interest rate swaps novated from the Fund | | | - | | | 2,875 |
General and administrative expense allocated from the Fund | | | 22,224 | | | 21,252 |
Amortization of increasing rate distributions(1) | | | 11,140 | | | - |
(1) Amortization of increasing rate distributions is offset in the preferred unitholder’s capital account by a non-cash distribution.
NOTE 16 – SUBSIDIARY GUARANTORS
On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. The Partnership’s Senior Notes, issued on July 30, 2012, are guaranteed by OLLC, a 100% owned subsidiary of the Partnership, and certain other future subsidiaries (the “Guarantor”, together with any future 100% owned subsidiaries that guarantee the Partnership’s Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned by the Partnership and the guarantees by the Subsidiaries are full and unconditional. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations. Refer to Note 9 – Long-Term Debt for details on the conditions of guarantor releases.
NOTE 17 – SUBSEQUENT EVENTS
In preparing the accompanying financial statements, we have reviewed events that have occurred after September 30, 2012, through the issuance of the financial statements.
Revolving Credit Facility Redetermination
On October 30, 2012, we completed our semi-annual borrowing base redetermination which resulted in an increase in the borrowing base of our revolving credit facility from $655 million to $730 million. Refer to Note 9 – Long-Term Debt for further details.
Acquisition of Oil and Gas Properties
On October 26, 2012, we entered into a purchase and sale agreement with a private seller to purchase predominately oil and natural gas properties in the Ark-La-Tex area for approximately $215 million. The acquisition is expected to close in the fourth quarter of 2012.
Derivative Contracts
In October 2012, we entered into new oil and natural gas derivative contracts for the years 2013 through 2017. These contracts were entered into with the same counterparties as our existing derivative contracts. The table below details the newly executed contracts.
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Commodity | | | Index | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | |
Oil positions: | | | | | | | | | | | | | | | | | | | |
Swaps | | | | | | | | | | | | | | | | | | | |
Hedged Volume (Bbls/d) | | | WTI | | | 627 | | | 1,000 | | | 931 | | | 868 | | | 817 | |
Average price ($/Bbls) | | | | | $ | 88.20 | | $ | 87.53 | | $ | 85.65 | | $ | 84.65 | | $ | 84.35 | |
| | | | | | | | | | | | | | | | | | | |
Natural gas positions: | | | | | | | | | | | | | | | | | | | |
Swaps | | | | | | | | | | | | | | | | | | | |
Hedged Volume (MMBtu/d) | | | Henry Hub | | | 767 | | | 715 | | | 671 | | | | | | | |
Average price ($/MMBtu) | | | | | $ | 3.99 | | $ | 4.27 | | $ | 4.43 | | | | | | | |
Collars | | | | | | | | | | | | | | | | | | | |
Hedged Volume (MMBtu/d) | | | Henry Hub | | | | | | | | | | | | 630 | | | 595 | |
Average floor price ($/MMBtu) | | | | | | | | | | | | | | $ | 4.00 | | $ | 4.00 | |
Average ceiling price ($/MMBtu) | | | | | | | | | | | | | | $ | 5.55 | | $ | 6.15 | |
Cost Allocation Methodology
On November 6, 2012, QRE GP approved a methodology for allocating general and administrative costs incurred by QRM on behalf of the Partnership upon the expiration of the current Services Agreement on December 31, 2012. Refer to Note 14 – Related Party Transactions for further details.
Completion of Senior Notes Exchange Offer
On November 7, 2012, the exchange offer for the Senior Notes, pursuant to a Form S-4 filed with the SEC, was completed. Refer to Note 9 – Long-term Debt for details.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our 2011 Annual Report and the consolidated financial statements and related notes therein. Our Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations. You should also read the following discussion and analysis together with the risk factors set forth in the 2011 Annual Report and in Part I—Item 1A “Risk Factors” of this report and the “Cautionary Statement Regarding Forward-Looking Information” in this report and in our Annual Report.
Overview
QR Energy, LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed on September 20, 2010, to receive certain assets of the affiliated entity, QA Holdings, LP (the “Predecessor”) and own other assets. Certain of the Predecessor’s subsidiaries (collectively known as the “Fund”) include Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC. Quantum Resources Management, LLC (“QRM”) provides management and operational services for us and the Fund. Our general partner is QRE GP, LLC (or “QRE GP”). We conduct our operations through our wholly owned subsidiary QRE Operating, LLC (“OLLC”). Our wholly owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of being a co-issuer of our debt securities.
Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploitation activities or acquire properties with existing production. The amount we realize for our production depends predominately upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differential and other factors. These risk factors are mitigated by our hedging program which generally hedges approximately 65% to 85% of our current and anticipated production over the next three-to-five year period. Oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. Oil and natural gas prices have experienced a general decline since 2011. The unweighted arithmetic average first day of-the-month prices for the prior 12 months decreased to $94.97/Bbl for oil and $2.83/MMbtu for natural gas as of September 30, 2012 from $96.19/Bbl for oil and $4.12/MMbtu for natural gas as of December 31, 2011. Further declines in future oil and natural gas market prices could have a negative impact on our reserve value and could result in an impairment of our oil and gas properties. For example, a hypothetical $10/Bbl decrease in the 12 month average of oil prices would decrease our reserves by $208.1 million, and a hypothetical $1/Mcf decrease in the 12 month average of natural gas prices would decrease our reserves by $104.9 million. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.
Results of Operations
Because affiliates of the Fund own 100% of our general partner and an aggregate 38.8% limited partner interest in us including all of our preferred and subordinated units as of September 30, 2012, each acquisition of assets from the Predecessor is considered a transfer of net assets between entities under common control. As a result, we are required to revise our financial statements to include the activities of all assets acquired from the Predecessor for all periods presented by the Partnership, 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 recast historical financial information for the three and nine months ended September 30, 2011 as if the oil and gas properties acquired from the Predecessor in October 2011 were owned by us for all periods presented for the Partnership. These results are presented for illustrative purposes only and have been prepared from the Predecessor’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.
Results of Operations - Continued
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Three Months Ended | | | Nine Months Ended |
| | | September 30, 2012 | | | September 30, 2011 (1) | | | September 30, 2012 | | | September 30, 2011 (1) |
Revenues: (2) | | | | | | | | | | | | |
Oil sales | | $ | 51,076 | | $ | 38,315 | | $ | 145,270 | | $ | 120,565 |
Natural gas sales | | | 8,623 | | | 17,453 | | | 27,604 | | | 50,474 |
NGLs sales | | | 4,860 | | | 8,521 | | | 18,848 | | | 22,930 |
Processing and other | | | 410 | | | 492 | | | 1,243 | | | 1,523 |
Total Revenue | | | 64,969 | | | 64,781 | | | 192,965 | | | 195,492 |
Operating Expenses: | | | | | | | | | | | | |
Lease operating expenses | | | 19,203 | | | 18,672 | | | 56,861 | | | 48,802 |
Production and other taxes | | | 4,693 | | | 4,480 | | | 14,224 | | | 13,431 |
Processing and transportation | | | 785 | | | 1,009 | | | 2,363 | | | 2,964 |
Total production expenses | | | 24,681 | | | 24,161 | | | 73,448 | | | 65,197 |
Depreciation, depletion and amortization | | | 21,298 | | | 19,965 | | | 61,428 | | | 58,295 |
Accretion of asset retirement obligations | | | 915 | | | 719 | | | 2,645 | | | 2,033 |
General and administrative and other | | | 9,232 | | | 8,338 | | | 26,345 | | | 22,577 |
Acquisition and transaction costs | | | 278 | | | - | | | 1,286 | | | - |
Total operating expenses | | | 56,404 | | | 53,183 | | | 165,152 | | | 148,102 |
Operating income | | | 8,565 | | | 11,598 | | | 27,813 | | | 47,390 |
Other income (expense): | | | | | | | | | | | | |
Realized gains (losses) on commodity derivative contracts | | | 13,375 | | | (39,072) | | | 35,668 | | | (79,924) |
Unrealized gains (losses) on commodity derivative contracts | | | (55,585) | | | 153,378 | | | 12,328 | | | 160,233 |
Interest expense, net | | | (11,533) | | | (19,950) | | | (28,398) | | | (39,161) |
Total other income (expense), net | | | (53,743) | | | 94,356 | | | 19,598 | | | 41,148 |
Income (loss) before income taxes | | | (45,178) | | | 105,954 | | | 47,411 | | | 88,538 |
Income tax benefit (expense) | | | 171 | | | (789) | | | (528) | | | (934) |
Net income (loss) | | $ | (45,007) | | $ | 105,165 | | $ | 46,883 | | $ | 87,604 |
Production data (3): | | | | | | | | | | | | |
Oil (MBbls) | | | 576 | | | 439 | | | 1,575 | | | 1,314 |
Natural gas (MMcf) | | | 3,400 | | | 3,834 | | | 10,587 | | | 11,709 |
Natural gas liquids (MBbls) | | | 202 | | | 200 | | | 559 | | | 576 |
Total (Mboe) | | | 1,345 | | | 1,278 | | | 3,899 | | | 3,842 |
Average Net Production (Boe/d) | | | 14,620 | | | 13,891 | | | 14,230 | | | 14,073 |
Average sales price per unit (4): | | | | | | | | | | | | |
Oil (Per Bbl) | | $ | 88.67 | | $ | 87.28 | | $ | 92.23 | | $ | 91.75 |
Natural gas (per Mcf) | | $ | 2.60 | | $ | 4.71 | | $ | 2.67 | | $ | 4.45 |
Natural gas liquids (Per Bbl) | | $ | 29.10 | | $ | 54.27 | | $ | 41.42 | | $ | 51.07 |
Average unit cost per Boe: | | | | | | | | | | | | |
Lease operating expense | | $ | 14.28 | | $ | 14.61 | | $ | 14.58 | | $ | 12.70 |
Production and other taxes | | $ | 3.49 | | $ | 3.51 | | $ | 3.65 | | $ | 3.50 |
Depreciation, depletion and amortization | | $ | 15.83 | | $ | 15.62 | | $ | 15.75 | | $ | 15.17 |
General and administrative expenses | | $ | 6.86 | | $ | 6.52 | | $ | 6.76 | | $ | 5.88 |
| (1) | These results of operations have been recast to include financial information for the assets acquired under common control. Refer to Note 2 – Significant Accounting Policies of Notes to Financial Statements (Unaudited) for basis of presentation. |
| (2) | Certain natural gas liquid sales for the three and nine months ended September 30, 2011 have been reclassified from natural gas sales to conform to current presentation. This resulted in an increase in natural gas liquid sales and a decrease in natural gas sales of $5.6 million and $15.5 million and an increase in natural gas liquid volumes of 103 MBbls and 304 MBbls and a decrease in natural gas volumes of 615 MMcf and 1,819 MMcf. |
| (3) | Includes certain volumes for natural gas (79 MMcf and 256 MMcf for the three and nine months ended September 30, 2012 and 130 MMcf and 366 MMcf for the three and nine months ended September 30, 2011) and natural gas liquids (35 MBbls and 104 Bbls for the three and nine months ended September 30, 2012 and 43 MBbls and 127 MBbls for the three and nine months ended September 30, 2011) for which revenues were reported on a net basis. |
| (4) | Does not include the impact of derivative instruments. |
Results of Operations - Continued
Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011
We recorded net loss of $45.0 million for the three months ended September 30, 2012 compared to net income of $105.2 million for the three months ended September 30, 2011. This change was primarily driven by a net decrease in realized and unrealized gains on commodity derivative contracts of $156.5 million.
Oil and Gas Revenues:
| | | | | | | | | | | | |
| | | Three Months Ended September 30, |
| | | | | | | | | Increase | | | Percentage |
| | | 2012 | | | 2011 | | | (Decrease) | | | Change |
Production: | | | | | | | | | | | | |
Oil (MBbls) | | | 576 | | | 439 | | | 137 | | | 31% |
Natural Gas (MMcf) | | | 3,400 | | | 3,834 | | | (434) | | | -11% |
NGL (MBbl) | | | 202 | | | 200 | | | 2 | | | 1% |
Total (Mboe) | | | 1,345 | | | 1,278 | | | 67 | | | 5% |
| | | | | | | | | | | | |
Average sales prices per unit: | | | | | | | | | | | | |
Oil (per Bbl) | | $ | 88.67 | | $ | 87.28 | | $ | 1.39 | | | 2% |
Natural Gas (per Mcf) | | | 2.60 | | | 4.71 | | | (2.11) | | | -45% |
NGL (per Bbl) | | | 29.10 | | | 54.27 | | | (25.17) | | | -46% |
Total (per Boe) | | | 48.00 | | | 50.30 | | | (2.30) | | | -5% |
| | | | | | | | | | | | |
Revenues: | | | | | | | | | | | | |
Oil sales | | $ | 51,076 | | $ | 38,315 | | $ | 12,761 | | | 33% |
Natural Gas sales | | | 8,623 | | | 17,453 | | | (8,830) | | | -51% |
NGL sales | | | 4,860 | | | 8,521 | | | (3,661) | | | -43% |
Total oil and gas revenue | | $ | 64,559 | | $ | 64,289 | | $ | 270 | | | 0% |
Total oil and gas revenue increased by $0.3 million to $64.6 million for the three months ended September 30, 2012 due higher production volumes despite a decrease in the prices per Boe mainly attributable to lower natural gas and NGL prices. The increase in production volumes is mainly attributable to increased oil production related to the assets acquired in the Prize Acquisition, offset by a decrease in natural gas and natural gas liquids production volumes due to the effects of natural declines in the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.
Production Expenses. Our production expense for the three months ended September 30, 2012 increased to $24.7 million from $24.2 million for the three months ended September 30, 2011, consisting mainly of an increase in lease operating expenses to $19.2 million, or $14.28 per Boe, for the three months ended September 30, 2012 from $18.7 million, or $14.61 per Boe for the three months ended September 30, 2011, and an increase in production and other taxes to $4.7 million, or $3.49 per Boe, from $4.5 million, or $3.51 per Boe for the three months ended September 30, 2011. The increase in production expenses is primarily attributable to the Prize Acquisition offset by a decrease in workover expenses in the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.
Depreciation, Depletion and Amortization Expenses. For the three months ended September 30, 2012, our depreciation, depletion and amortization (“DD&A”) expenses were $21.3 million, or $15.83 per Boe, as compared to $20.0 million, or $15.62 per Boe, for the three months ended September 30, 2011. The increase in DD&A expense is mainly attributable to the Prize Acquisition for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.
General and Administrative and Other Expenses. For the three months ended September 30, 2012 our general and administrative and other expenses increased to $9.2 million, or $6.86 per Boe, as compared to $8.3 million, or $6.52 per Boe, for the three months ended September 30, 2011. The increase is mainly attributable to the higher personnel costs associated with increasing our staffing levels to meet our current organizational needs in the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.
Effects of Commodity Derivative Contracts. For the three months ended September 30, 2012, our realized gains on commodity derivative contracts increased to $13.4 million from a realized loss of $39.1 million for the three months ended September 30, 2011. Unrealized gains (losses) on commodity derivative contracts decreased to a $55.6 million loss for the three months September 30, 2012 from a $153.4 million gain for the three months ended September 30, 2011. Unrealized gains and losses result from changes in the future commodity prices as compared to the fixed price of our open commodity derivative contracts. Realized gains and losses result from the settlement of derivative contracts at the market price as compared to the fixed contract price.
The change in realized and unrealized gains (losses) is mainly attributable to increasing oil and gas prices as compared to our fixed price derivative contracts in the three months ended September 30, 2012 as compared to decreasing oil and gas prices in the three months ended September 30, 2011, as well as the modification of certain oil derivative contracts during the third quarter of 2011.
Interest Expense, net. Net interest expense decreased to $11.5 million for the three months ended September 30, 2012 as compared to $20.0 million for the three months ended September 30, 2011. The net decrease in realized and unrealized losses on derivative contracts is related to lower interest rates in September 30, 2012 versus September 30, 2011 offset by an increase in interest expense of $4.1 million related to the Senior Notes issued during the three months ended September 30, 2012.
Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011
We recorded net income of $46.9 million for the nine months ended September 30, 2012 compared to net income of $87.6 million for the nine months ended September 30, 2011. This change was primarily driven by a net decrease in realized and unrealized gains on commodity derivative contracts of $32.3 million and an increase in lease operating expenses of $8.1 million.
Oil and Gas Revenues:
| | | | | | | | | | | | |
| | | Nine Months Ended September 30, |
| | | | | | | | | Increase | | | Percentage |
| | | 2012 | | | 2011 | | | (Decrease) | | | Change |
Production: | | | | | | | | | | | | |
Oil (MBbls) | | | 1,575 | | | 1,314 | | | 261 | | | 20% |
Natural Gas (MMcf) | | | 10,587 | | | 11,709 | | | (1,122) | | | -10% |
NGL (MBbl) | | | 559 | | | 576 | | | (17) | | | -3% |
Total (Mboe) | | | 3,899 | | | 3,842 | | | 57 | | | 1% |
| | | | | | | | | | | | |
Average sales prices per unit: | | | | | | | | | | | | |
Oil (per Bbl) | | $ | 92.23 | | $ | 91.75 | | $ | 0.48 | | | 1% |
Natural Gas (per Mcf) | | | 2.67 | | | 4.45 | | | (1.78) | | | -40% |
NGL (per Bbl) | | | 41.42 | | | 51.07 | | | (9.65) | | | -19% |
Total (per Boe) | | | 49.17 | | | 50.49 | | | (1.32) | | | -3% |
| | | | | | | | | | | | |
Revenues: | | | | | | | | | | | | |
Oil sales | | $ | 145,270 | | $ | 120,565 | | $ | 24,705 | | | 20% |
Natural Gas sales | | | 27,604 | | | 50,474 | | | (22,870) | | | -45% |
NGL sales | | | 18,848 | | | 22,930 | | | (4,082) | | | -18% |
Total oil and gas revenue | | $ | 191,722 | | $ | 193,969 | | $ | (2,247) | | | -1% |
Total oil and gas revenue decreased by $2.2 million to $191.7 million for the nine months ended September 30, 2012 due to lower sales prices per Boe mainly attributed to decreased prices for natural gas and natural gas liquids, partially offset by a slight increase in the total production volumes of 57 Mboe. The increase in production volumes is mainly attributable to increased oil production related to the assets acquired in the Prize Acquisition, offset by a decrease in natural gas and natural gas liquids production volumes due to the effects of natural declines in the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.
Production Expenses. Our production expense for the nine months ended September 30, 2012 increased to $73.4 million from $65.2 million for nine months ended September 30, 2011, consisting mainly of an increase in lease operating expenses to $56.9 million, or $14.58 per Boe, for the nine months ended September 30, 2012 from $48.8 million, or $12.70 per Boe for the nine months ended September 30, 2011, and an increase in production and
other taxes to $14.2 million, or $3.65 per Boe, from $13.4 million, or $3.50 per Boe for the nine months ended September 30, 2011. The increase in production expenses is attributable to the Prize Acquisition, an increase in workover expenses, and an increase in other lease operating expenses in the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.
Depreciation, Depletion and Amortization Expenses. For the nine months ended September 30, 2012 our DD&A expenses were $61.4 million, or $15.75 per Boe as compared to $58.3 million, or $15.17 per Boe for the nine months ended September 30, 2011. The increase in DD&A expense is due mainly attributable to the Prize Acquisition during the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.
General and Administrative and Other Expenses. For the nine months ended September 30, 2012 our general and administrative and other expenses increased to $26.3 million, or $6.76 per Boe, as compared to $22.6 million, or $5.88 per Boe for the nine months ended September 30, 2011. The increase is mainly attributable to the higher personnel costs associated with increasing our staffing levels to meet our current organizational needs in the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.
Effects of Commodity Derivative Contracts. For the nine months ended September 30, 2012, our realized gains increased to a $35.7 million gain from a realized loss of $79.9 million in the nine months ended September 30, 2011. Unrealized gains on commodity derivative contracts decreased to $12.3 million for the nine months September 30, 2012 from $160.2 million for the nine months ended September 30, 2011. Unrealized gains and losses result from changes in the future commodity prices as compared to the fixed price of our open commodity derivative contracts. Realized gains and losses result from the settlement of derivative contracts at the market price as compared to the fixed contract price.
The change in realized and unrealized gains (losses) is mainly attributable to increasing oil and gas prices as compared to our fixed price derivative contracts in the three months ended September 30, 2012 as compared to decreasing oil and gas prices in the three months ended September 30, 2011, as well as the modification of certain oil derivative contracts during the third quarter of 2011.
Interest Expense, net. Net interest expense decreased to $28.4 million for the nine months ended September 30, 2012 as compared to $39.2 million for the nine months ended September 30, 2012. The net decrease in realized and unrealized losses on derivative contracts is related to lower interest rates at September 30, 2012 as compared to September 30, 2011 partially offset by a commitment fee of $1.6 million related to the Bridge Loan and an increase in interest expense of $4.6 million related to the Senior Notes in the nine months ended September 30, 2012.
Liquidity and Capital Resources
Our cash flow from operating activities for the nine months ended September 30, 2012 was $110.4 million.
Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under our credit facility, and debt and equity offerings. The capital markets continue to experience volatility. Many financial institutions have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to current credit conditions includes our credit facility, debt securities, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.
We entered into a Second Amendment to the Credit Agreement on March 16, 2012 to provide for additional derivative contracts to cover production to proved reserves to be acquired.
In April 2012, we entered into the Third Amendment to the Credit Agreement whereby increasing our credit facility from $750 million to $1.5 billion, increasing our borrowing base from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017.
On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 16 – Subsidiary Guarantors for further details.
On July 30, 2012, we, and our wholly-owned subsidiary QRE FC, issued $300 million of 9.25% Senior Notes due 2020. Under the Credit Agreement we are required to reduce our borrowing base by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. As a result of the issuance of the Senior Notes on July 30, 2012, our borrowing base was reduced by $75 million to $655 million from $730 million. On the same date, we made a payment on our outstanding borrowings under our revolving credit facility of $291.5 million using the cash proceeds from the Senior Notes issuance and cash on hand. On October 30, 2012, we were notified of an increase in our borrowing base, as part of our semi-annual borrowing base redetermination, from $655 million to the borrowing base prior to the issuance of the Senior Notes of $730 million. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 9 – Long-Term Debt for further details.
As of September 30, 2012, our liquidity of $355.0 million consisted of $25.1 million of available cash and $329.9 million of availability under our credit facility after giving consideration to $0.1 million of outstanding letters of credit. As of September 30, 2012, we had $325 million of borrowings outstanding. As of November 8, 2012 we had $325 million of borrowings outstanding with borrowing availability of $404.9 million ($730 million of borrowing base less $325 million of outstanding borrowing and $0.1 million of outstanding letters of credit) under our credit facility. The borrowing base is redetermined as of May 1 and November 1 of each year. The administrative agent of our Credit Agreement accepted the Third Amendment to the Credit Agreement as our May 1 redetermination and our November redetermination was completed on October 30, 2012 as discussed above. In addition, we may request additional capacity for acquisitions of a minimum of the lesser of $50 million or ten percent of the then-existing borrowing base. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility.
A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands. As of September 30, 2012, we had letters of credit in the amount of $0.1 million outstanding for utilities.
On April 17, 2012, we issued 6,202,263 common units representing limited partnership interests in us, and the Fund sold 11,297,737 common units it held in us, to the public pursuant to a registration statement filed with the SEC. In conjunction with the Equity Offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. Proceeds from the Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.
On September 28, 2012, we announced that our general partner declared a cash distribution to our common and subordinated unitholders and our general partner at the third quarter rate of $0.4875 per unit. Our Partnership Agreement obligates us to make cash distributions to our preferred unitholders at a rate of $0.21 per unit per quarter. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources.
Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. We believe our cash flows provided by operating activities will be sufficient to meet our operating requirements for the next twelve months.
As of September 30, 2012, we had a positive working capital balance of $46.7 million.
Capital Expenditures
Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage). The primary purpose of maintenance capital is to maintain our production and asset base at a steady level over the long term in order to maintain our distributions per unit. For 2012, we have estimated our maintenance capital expenditures to be approximately $52.0 million. During the nine months ended September 30, 2012, we have expended $80.6 million of total capital expenditures. We currently expect 2012 total capital spending for the development of our oil and natural gas properties to be approximately $85.0 million.
Growth capital expenditures are capital expenditures that are expected to increase our production and the size of our asset base. The primary purpose of growth capital is to acquire producing assets that will primarily increase our distributions per unit and secondarily increase the rate of development and production of our existing properties in a manner which is expected to be accretive to our unitholders. We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisitions of oil and natural gas properties in 2012 through a combination of cash, borrowings under our credit facility and the issuance of equity securities. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. Although we closed the Prize Acquisition in April 2012 and entered into a purchase and sale agreement to purchase additional preliminary properties expected to close in the fourth quarter 2012, as discussed in Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 3, Acquisitions, we cannot estimate further growth capital expenditures related to acquisitions, including potential acquisitions of producing properties from the Fund, as 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 control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we 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 the remainder of 2012. 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 capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.
Credit Facilities
Revolving Credit Facility
We entered into a Second Amendment to the Credit Agreement on March 16, 2012 to provide for additional derivative contracts to cover production of proved reserves to be acquired.
In April 2012, we entered into the Third Amendment to the Credit Agreement whereby increasing our credit facility from $750 million to $1.5 billion, increasing our borrowing base from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017. The Third Amendment became effective upon the closing of the Prize Acquisition.
As a result of the issuance of the Senior Notes on July 30, 2012, our borrowing base was reduced by $75 million to $655 million from $730 million. On the same date, we made a payment on our outstanding borrowings under our revolving credit facility of $291.5 million using the cash proceeds from the Senior Notes issuance and cash on hand. In connection with the reduction of the borrowing base, we wrote-off approximately $0.7 million of deferred loan costs associated with the Credit Agreement. On October 30, 2012, we were informed of an increase in our borrowing base, as part of our semi-annual borrowing base redetermination, from $655 million to the borrowing base prior to the issuance of the Senior Notes of $730 million.
As of September 30, 2012, we had $325 million of borrowings outstanding under our revolving credit facility and $0.1 million of letters of credit outstanding resulting in $329.9 million of borrowing availability. As of
December 31, 2011, we had $500.0 million of borrowings and $0.4 million letters of credit outstanding resulting in $129.6 million of borrowing availability
As of November 8, 2012, we had $325 million of borrowings outstanding under our revolving credit facility and $404.9 million of borrowing availability.
As of September 30, 2012, we were party to a five-year credit agreement that governs our $1.5 billion revolving credit facility with a borrowing base of $655 million. The borrowing base is subject to redetermination on a semi-annual basis and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ price assumptions, and other various factors unique to each member bank. The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. In the future, we may be unable to access sufficient capital under our new credit facility as a result of (i) a decrease in our borrowing base due to subsequent borrowing base redeterminations, 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 additional oil and natural gas properties as 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 the Credit Agreement. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under the Credit Agreement. We completed our semi-annual redetermination on October 30, 2012 as discussed above.
Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% 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 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee ranging from 0.375% to 0.50% per annum.
The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our 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; prepay certain indebtedness; and to provide audited financial statements within 90 days of year end and quarterly unaudited financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of September 30, 2012, we were in compliance with all of the Credit Agreement covenants.
Bridge Loan Commitment
In conjunction with the Prize Acquisition, we entered into a Bridge Loan Commitment to provide an additional $200 million of bank loans to fund the acquisition as needed. We did not utilize any borrowings under the commitment and as of May 10, 2012 the Bridge Loan Commitment was terminated by us. We incurred $1.6 million of commitment fees related to the Bridge Loan Commitment which is recorded in interest expense for the nine months ended September 30, 2012.
9.25% Senior Notes
On July 30, 2012, we and our wholly-owned subsidiary QRE FC, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 9.25% Senior Notes, due 2020. The Senior Notes were issued at 98.62% of par. We received approximately $291.2 million of cash proceeds, net of discount and underwriting fees, with total net proceeds of approximately $290.2 million, after $1.0 million of offering costs. We used the net proceeds from the sale of the Senior Notes to repay borrowings outstanding under our credit facility. We will have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Our and QRE FC’s obligations under the Senior Notes are guaranteed by OLLC. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor’s, other, debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Note 16 – Subsidiary Guarantors for further details of our guarantors.
The indenture governing the Senior Notes (the “Indenture”) restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, or repurchase, equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants. The Indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the Senior Notes
On September 7, 2012, we filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes to exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012. The exchange offer was completed on November 7, 2012.
Commodity Derivative Contracts
Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on the prices of oil and natural gas and our ability to maintain and increase production through acquisitions and exploitation and development projects. For further discussion of our derivative activities, see Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 5, Derivative Activities.
Cash Flows
Cash flows provided (used) by type of activity were as follows for the periods indicated:
| | | | | | |
| | | | | | |
| | | Nine Months Ended |
| | | September 30, 2012 | | | September 30, 2011 |
Net cash provided by (used in): | | | | | | |
Operating activities | | $ | 110,386 | | $ | 22,381 |
Investing activities | | | (302,602) | | | (42,590) |
Financing activities | | | 199,927 | | | 19,226 |
Operating Activities
Our cash flow from operating activities for the nine months ended September 30, 2012 was $110.4 million compared to $22.4 million in cash flow from operating activities for the nine months ended September 30, 2011. The increase in cash flow from operating activities is mainly attributable to the realized loss on commodity derivatives modifications during the nine months ended September 30, 2011.
Investing Activities
Our cash flow used in investing activities for the nine months ended September 30, 2012 was $302.6 million compared to cash flows used in investing activities of $42.6 million for the nine months ended September 30, 2011. The increase in cash flow used in investing activities is mainly attributable to the Prize Acquisition and capital spending related to our drilling activities during the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.
Financing Activities
Our cash flow provided by financing activities for the nine months ended September 30, 2012 was $199.9 million compared to cash flows provided by financing activities of $19.2 million for the nine months ended September 30, 2011. The increase in the cash provided by financing activities is mainly attributed to the increase in net proceeds received from the Equity Offering of $120.1 million and proceeds received from the issuance of the Senior Notes of $295.8 million, partially offset by higher net payments on our revolving credit facility of $216.0 million and an increase in distributions of $39.7 million during the nine months ended September 30, 2012 when compared to the nine months ended September 30, 2011.
Contractual Obligations
There were no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements as of September 30, 2012. Our level of capital expenditures will vary in the future periods depending on the success we experience in our acquisition, development and exploitation activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.
Off-Balance Sheet Arrangements
As of September 30, 2012, we have no off-balance sheet arrangements.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon the unaudited consolidated financial statements, which have been prepared in accordance with U.S. GAAP. Preparation of these unaudited consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our 2011 Annual Report during the three months ended September 30, 2012.
Recent 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 IFRSs (ASU 2011-04). The amendments in ASU 2011-04 are the result of the FASB's and the International Accounting Standards Board's (IASB) work to develop common requirements for measuring fair value and for disclosing information about fair value measurements in accordance with GAAP in the United States and the International Financial Reporting Standards (IFRS). ASU 2011-04 explains how to measure fair value and changes the wording used to describe many of the fair value requirements in GAAP, but does not require additional fair value measurements. This guidance became effective for interim and annual periods beginning on or after December 15, 2011, with early adoption prohibited. This amendment was adopted by us on January 1, 2012 and did not have a material impact on our financial position, results of operations or cash flows.
In December 2011, the FASB issued ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). The objective of this Update is to provide enhanced disclosures that will enable the users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The amendment will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to the master netting arrangement. This scope would include financial and derivative instruments that either offset in accordance with U.S. GAAP or are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with U.S. GAAP. This amendment becomes effective for annual reporting periods beginning on or after January 1, 2013, and the interim periods within those annual periods. We are evaluating the potential impacts this ASU will have on our disclosures.
Non-GAAP Financial Measures
We include in this report the non-GAAP financial measures Adjusted EBITDA and Distributable Cash Flow and provide our calculations of Adjusted EBITDA and Distributable Cash Flow and reconciliations to their most directly comparable financial measures calculated and presented in accordance with U.S. GAAP. As discussed below, we have revised our calculation of Adjusted EBITDA from prior periods.
Adjusted EBITDA
We define Adjusted EBITDA as net income:
| · | Interest expense, including realized and unrealized gains and losses on interest rate derivative contracts; |
| · | Depreciation, depletion, and amortization; |
| · | Accretion of asset retirement obligations; |
| · | Unrealized losses on gas imbalances |
| · | Unrealized losses on commodity derivative contracts; |
| · | General and administrative expenses that are allocated to us in accordance with GAAP in excess of the administrative services fee paid by our general partner; |
| · | Unrealized gains on gas imbalances; and |
| · | Unrealized gains on commodity derivative contracts. |
In our quarterly report for the six months ended June 30, 2012, we revised our calculation of Adjusted EBITDA to, in addition to line items which were added or subtracted from net income in our previous Adjusted EBITDA calculation, add or subtract to net income unrealized losses and gains on gas imbalances, respectively.
We use Adjusted EBITDA, as defined under the Services Agreement, to calculate the quarterly administrative services fee our general partner pays to QRM under the services agreement between our general partner and QRM.
Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:
| · | the cash flow generated by our assets, without regard to financing methods, capital structure or historical cost basis; and |
| · | the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness. |
In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.
Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.
Distributable Cash Flow
We define Distributable Cash Flow as Adjusted EBITDA less cash interest expense, estimated maintenance capital expenditures, distributions to preferred unitholders, and the management incentive fee. Distributable Cash Flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserve by our general partner) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable Cash Flow is also an important financial measure for our unitholders as it serves as an indicator of our success in providing a cash return on investment. Specifically, Distributable Cash Flow indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable Cash Flow is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the yield is based on the amount of cash distributions the entity pays to a unitholder compared to its unit price.
Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate Distributable Cash Flow in the same manner.
The table below presents our calculation of Adjusted EBITDA and Distributable Cash Flow and a reconciliation of Adjusted EBITDA and Distributable Cash Flow to net income, our most directly comparable GAAP financial measures, for each of the periods indicated.
| | | | | | | | | | | | |
| | | Three Months Ended | | | Nine Months Ended |
| | | September 30, 2012 | | | September 30, 2011 1 | | | September 30, 2012 | | | September 30, 2011 1 |
Reconciliation of net income (loss) to Adjusted EBITDA | | | | | | | | | | | | |
and Distributable Cash Flow: | | | | | | | | | | | | |
Net income (loss) | | $ | (45,007) | | $ | 105,165 | | | 46,883 | | | 87,604 |
Unrealized losses (gains) on commodity derivative contracts | | | 55,585 | | | (153,378) | | | (12,328) | | | (160,233) |
Loss on modification of derivative contracts | | | - | | | 42,654 | | | - | | | 83,399 |
Unrealized loss (gain) on gas imbalances | | | 371 | | | (703) | | | 73 | | | (143) |
Depletion, depreciation and amortization | | | 21,298 | | | 19,965 | | | 61,428 | | | 58,295 |
Accretion of asset retirement obligations | | | 915 | | | 719 | | | 2,645 | | | 2,033 |
Interest expense | | | 11,533 | | | 19,950 | | | 28,398 | | | 39,161 |
Income tax expense (benefit) | | | (171) | | | 789 | | | 528 | | | 934 |
General and administrative expense in excess | | | | | | | | | | | | |
of administrative services fee | | | 7,675 | | | 8,996 | | | 22,374 | | | 21,903 |
Adjusted EBITDA | | $ | 52,199 | | $ | 44,157 | | $ | 150,001 | | $ | 132,953 |
| | | | | | | | | | | | |
Cash interest expense | | | (8,703) | | | (4,907) | | | (21,348) | | | (13,237) |
Estimated maintenance capital expenditures | | | (13,000) | | | (12,500) | | | (38,500) | | | (37,500) |
Distributions to preferred unitholders | | | (3,500) | | | - | | | (10,500) | | | - |
Management incentive fee earned by GP | | | (3,738) | | | - | | | (6,121) | | | - |
Distributable Cash Flow | | $ | 23,258 | | $ | 26,750 | | $ | 73,532 | | $ | 82,216 |
| (1) | 2011 Adjusted EBITDA has been revised to conform with current period presentation. |
The increase in Adjusted EBITDA of $8.0 million to $52.2 million for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011 is mainly attributable to the increase of realized gains on commodity derivative contracts. The increase of $17.0 million to $150.0 million for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 is mainly attributable to the increase of realized gains on commodity derivative contracts, partially offset by higher production expense, the increase in the quarterly general and administrative fee and a decrease in revenue.
The decrease in Distributable Cash Flow of $3.5 million to $23.3 million in the three months ended September 30, 2012 compared to the three months ended September 30, 2011 is mainly attributable to distributions to preferred untiholders and the management incentive fee earned by QRE GP that were not present in the three months ended September 30, 2011 as well as an increase in cash interest paid, partially offset by an increase in Adjusted EBITDA during the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. The decrease in Distributable Cash Flow of $8.7 million to $73.5 million for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011 is attributable to distributions to preferred unitholders and the management incentive fee earned by QRE GP that were not present in the nine months ended September 30, 2011 as well as an increase in cash interest paid, partially offset by an increase in Adjusted EBITDA during the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information about market risks for the third quarter of 2012 did not change materially from the disclosures in Item 7A of our 2011 Annual Report.
Derivative Instruments and Hedging Activity
We are exposed to various risks including energy commodity price risk. When oil and natural gas prices decline significantly, our ability to finance our capital budget and operations could be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the effect it could have on our operations. The types of derivative instruments that we typically utilize are swaps. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 65% to 85% of our current and anticipated production over the next three-to-five year period. Our hedge policies and objectives may change significantly as commodities prices or price futures change.
We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. We do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. Each of the counterparties to our derivative contracts is a lender in our Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Credit Agreement. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 5, Derivative Activities for additional information on our commodity derivatives.
Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates into fixed interest rates. We are exposed to market risk on our open contracts, to the extent of changes in LIBOR. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 5, Derivative Activities for additional information on our interest rate swaps.
We account for our derivative activities whereby every derivative instrument is recorded on the balance sheet as either an asset or liability measured at fair value. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 5, Derivative Activities for further details.
Item 4. Controls and Procedures
As discussed below, we have determined that newly implemented controls related to our previously identified material weaknesses are designed and operating effectively and, therefore, have concluded that, as of June 30, 2012, such material weaknesses have been remediated.
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) we have evaluated, under the supervision and with the participation of our Chief Executive Officer, our principal executive officer and Chief Financial Officer, our principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of September 30, 2012). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.
Based on the evaluation, the principal executive officer and the principal financial officer concluded that the Partnership's disclosure controls and procedures were effective to provide reasonable assurance as of September 30, 2012.
Material Weakness Previously Identified
As previously discussed in Item 9A. “Controls and Procedures” of our 2011 Annual Report on Form 10-K, we reported material weaknesses in certain control activity levels:
| · | We did not maintain effective controls over the completeness and accuracy of the inputs with respect to the DD&A calculation. Specifically, we did not develop detailed procedures for the accounting staff to follow in order to provide reasonable assurance that the inputs to the calculation are complete and accurate. |
| · | We did not maintain effective controls over the completeness and accuracy of certain calculations used in recording mark to market for derivative expense, the general and administrative allocation and ad valorem taxes. Specifically, we did not maintain effective controls related to the detailed review of these calculations. |
Remediation of Previously Identified Material Weaknesses
During the three months ended March 31, 2012, we implemented the following additional procedures to address the material weaknesses in our internal control over financial reporting and the ineffectiveness of our disclosure controls and procedures.
| · | Re-designed procedures for the DD&A calculation, which includes the review of inputs into the calculation, supporting schedules and analysis. |
| · | Spreadsheets used in the calculations of mark to market for derivative income or expense, the general and administrative allocation and ad valorem taxes have been reviewed to provide reasonable assurance that they are functioning as intended. |
| · | Additional levels of review have been put into place in order to strengthen the overall review process. |
| · | Compensating controls have been strengthened to identify material anomalies. |
We have assessed the design and tested the operating effectiveness of the newly implemented controls over the DD&A calculation and the calculations used in recording mark to market for derivative income or expense, the general and administrative allocation and ad valorem taxes and found them to be effective. As such, we concluded the remediation measures described above were sufficient to remediate both material weaknesses in internal control over financial reporting as of June 30, 2012.
Changes in Internal Control over Financial Reporting.
There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Please see Part 1, - Item 3 “- Legal Proceedings” in our 2011 Annual Report on Form 10-K. In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We currently have no legal proceedings with a probable adverse outcome. Therefore, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
Item 1A. Risk Factors
There have been no material changes to the risk factors described in the Partnership’s 2011 Annual Report on Form 10-K and the Partnership’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
Determination of Services Fee Methodology
Beginning on January 1, 2013, QRM will be entitled to a quarterly administrative services fee based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. The fee will include direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If the Fund raises a second fund, the quarterly administrative services costs will be further divided to include the second fund as well. The allocation methodology was developed with the assistance of a third-party consultant with extensive experience in this area. These fees will be included in general and administrative expenses in our consolidated statement of operations. QRM will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.
Item 6. Exhibits
The following documents are included as exhibits to the Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.
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Exhibit Number | | | Description |
2.1 | | --- | Purchase and Sale Agreement, dated as of March 19, 2012, by and among QRE Operating, LLC, Prize Petroleum, LLC and Prize Pipeline, LLC (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on March 22, 2012). |
3.1 | | --- | Certificate of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010). |
3.2 | | --- | First Amended and Restated Agreement of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010). |
3.3 | | --- | Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, dated as of October 3, 2011 (Incorporated herein by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011). |
3.4 | | --- | Certificate of Formation of QRE GP, LLC (Incorporated by reference to Exhibit 3.4 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010). |
3.5 | | --- | Amended and Restated Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010). |
4.1 | | --- | Indenture dated as of July 30, 2012 among QR Energy, LP, QRE Finance Corporation and QRE Operating, LLC and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on July 31, 2012). |
4.2 | | --- | Registration Rights Agreement dated as of July 30, 2012 among QR Energy, LP, QRE Finance Corporation, QRE Operating, LLC and Citigroup Global Markets Inc., Barclays Capital Inc., Credit Agricole Securities (USA) Inc., RBC Capital Markets, LLC, RBS Securities Inc. and Wells Fargo Securities, LLC, as representatives of the several initial purchasers (Incorporated by reference to Exhibit 4.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on July 31, 2012). |
31.1 | * | --- | Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. |
31.2 | * | --- | Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. |
32.1 | ** | --- | Certification of the Chief Executive Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2 | ** | --- | Certification of the Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
101.INS | ** | --- | XBRL Instance Document |
101.SCH | ** | --- | XBRL Taxonomy Extension Schema Document |
101.CAL | ** | --- | XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF | ** | --- | XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB | ** | --- | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE | ** | --- | XBRL Taxonomy Extension Presentation Linkbase Document |
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* Filed as an exhibit to this Quarterly Report on Form 10-Q.
** Furnished as an exhibit to this Quarterly Report on Form 10-Q.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| By: | QRE GP, LLC, |
| | its General Partner |
Dated: November 8, 2012 | By: | /s/ Alan L. Smith |
| | Alan L. Smith |
| | Chief Executive Officer and Director |
Dated: November 8, 2012 | By: | /s/ Cedric W. Burgher |
| | Cedric W. Burgher |
| | Chief Financial Officer |
