QR ENERGY, LP
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 and exploit producing oil and natural gas properties in North America. Certain of the Predecessor’s subsidiary limited partnerships (collectively known as the “Fund”), comprise 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”).
On December 22, 2010 (the “Closing Date”), we completed our initial public offering (“IPO”) of 15,000,000 common units representing limited partner interests in the Partnership at $20.00 per common unit. Total net proceeds from the sale of the common units in the IPO were $279.8 million ($300.0 million less $19.5 million underwriters’ discount and $0.7 million structuring fee). IPO related costs and expenses totaling $5.1 million were borne entirely by the Fund.
On the Closing Date, we also entered into the following agreements and transactions with the Fund:
Contribution Agreement and Concurrent Transactions
A Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) was executed on the Closing Date by and among the Fund, the Partnership and QRE GP with net assets contributed by the Fund to the Partnership as follows:
| Oil and gas properties, net | | $ | 444,671 | |
| Natural gas imbalance | | | (1,247 | ) |
| Long-term debt | | | (200,000 | ) |
Derivative instrument liability, net (1) | | | (1,425 | ) |
| Asset retirement obligation | | | (18,263 | ) |
| Net Assets | | $ | 223,736 | |
| | (1) | Novation of derivative instruments from the Fund to the Partnership was concurrent with the IPO but not part of the Contribution Agreement and such derivative instruments were transferred at fair value on the Closing Date. The fair value is reflected in the Predecessor’s book value by the means of non-recurring valuation measurements as of the date of transfer. |
In exchange for the net assets above, the Fund received 11,297,737 common and 7,145,866 subordinated limited partner units and a $300.0 million cash distribution. QRE GP made a capital contribution of $0.7 million in exchange for 35,729 general partner units. The contribution was received in January 2011.
As a result of these transactions, at December 31, 2010, our ownership structure comprised a 0.1% general partnership interest held by QRE GP, 55.1% in limited partner interest held by the Fund and 44.8% in limited partner interests held by public unitholders.
On January 3, 2011, the underwriters exercised their over-allotment option in full for 2,250,000 common units issued by the Partnership at $20.00 per unit. Total net proceeds from the sale of these common units, after deducting the underwriters’ discount and structuring fee, were approximately $42.0 million which, in accordance with the Contribution Agreement were distributed to the Fund as consideration for assets contributed on the Closing Date and reimbursements for pre-formation capital expenditures.
At June 30, 2011, our ownership structure comprised a 0.1% general partner interest held by QRE GP, a 51.6% in limited partner interest held by the Fund and a 48.3% limited partner interest held by 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 for complete annual financial statements. The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. During interim periods, we follow the accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010 (the “Annual Report”), filed with the United States Securities and Exchange Commission (the “SEC”). Please refer to the footnotes to the financial statements in the Annual Report when reviewing the interim financial results. The unaudited consolidated financial statements for the three and six months ended June 30, 2011 and 2010 include all adjustments (consisting of normal recurring adjustments) we believe are necessary for a fair statement of the results for the interim periods. Operating results for the three and six month periods ended June 30, 2011 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2011. 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 Annual Report.
During the three months ended June 30, 2011, we recorded out-of-period adjustments related to the three months ended March 31, 2011 that decreased our income before taxes for the three months ended June 30, 2011 by $1.2 million. These adjustments include a $2.0 million decrease in revenue partially offset by out-of-period decreases of $0.6 million in production expenses and $0.2 million in depletion expense. After evaluating the quantitative and qualitative aspects of the errors, we concluded our previously issued financial statements were not materially misstated and the effect of recognizing these adjustments in the consolidated financial statements for the three months ended June 30, 2011 is not material to our results of operations, financial position, or cash flows.
Accounting Policy Updates/Revisions
The accounting policies followed by the Partnership and the Predecessor are set forth in Note 2 of the Notes to Consolidated Financial Statements in our Annual Report. There have been no significant changes to these policies during the six months ended June 30, 2011.
Recent Accounting Pronouncements
In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements (ASU 2010-06) requiring additional disclosures about fair value measurements including transfers in and out of Levels 1 and 2 and increased disclosure of different types of financial instruments. For the reconciliation of Level 3 fair value measurements, information about purchases, sales, issuances and settlements should be presented separately. This guidance is effective for annual and interim reporting periods beginning after December 15, 2009 for most of the new disclosures and for periods beginning after December 15, 2010 for the new Level 3 disclosures. Our adoption did not have a material impact on our consolidated financial statements.
In December 2010, the FASB issued Accounting Standards Update No. 2010-29 – Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations. The new guidance specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combinations(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The update also expands the supplemental pro forma disclosures under Topic 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The update is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We adopted this update on January 1, 2011 and it will be applied if we enter into a business combination transaction.
NOTE 3 – FAIR VALUE MEASURMENTS
Our financial instruments, including cash and cash equivalents, 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). The statement 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 requiring 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 forward commodity price and volatility curves. The curves are obtained from independent pricing services.
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 forward interest rates and volatility curves. The curves are obtained from independent pricing services.
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 June 30, 2011 and December 31, 2010.
| As of June 30, 2011 | | Total | | | Level 1 | | | Level 2 | | | Level 3 | |
| Assets from commodity derivative contracts | | $ | 15,099 | | | $ | - | | | $ | 15,099 | | | $ | - | |
| Assets from interest rate derivative contracts | | | 1,761 | | | | - | | | | 1,761 | | | | - | |
| | | $ | 16,860 | | | $ | - | | | $ | 16,860 | | | $ | - | |
| | | | | | | | | | | | | | | | | |
| Liabilities from commodity derivative contracts | | $ | (7,198 | ) | | $ | - | | | $ | (7,198 | ) | | $ | - | |
| Liabilities from interest rate derivative contracts | | | (3,535 | ) | | | - | | | | (3,535 | ) | | | - | |
| | | $ | (10,733 | ) | | $ | - | | | $ | (10,733 | ) | | $ | - | |
| | | | | | | | | | | | | |
| As of December 31, 2010 | | Total | | | Level 1 | | | Level 2 | | | Level 3 | |
| Assets from commodity derivative contracts | | $ | 18,047 | | | $ | - | | | $ | 18,047 | | | $ | - | |
| Liabilities from commodity derivative contracts | | $ | (26,877 | ) | | $ | - | | | $ | (26,877 | ) | | $ | - | |
On February 28, 2011, the Predecessor novated certain interest rate derivative instruments to us. These derivative instruments were accounted for at fair value on a nonrecurring basis of a $2.9 million net asset position (See Note 4). These derivative instruments are classified as Level 2 fair value measurements.
In June 2011, we entered into modifications of all our existing oil fixed price swap derivative contracts, effectively settling those liability positions as of June 22, 2011. These modifications were accounted for at fair value on a nonrecurring basis of $40.7 million (See Note 4). These modifications are classified as Level 2 fair value measurements.
NOTE 4 – DERIVATIVE ACTIVITIES
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 both the market price of oil, natural gas and natural gas liquids. We use derivatives to reduce our risk of changes in the prices of oil and natural gas. Our policies do not permit the use of derivatives for speculative purposes. 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. Each of the counterparties to our derivative contracts is a lender under our credit facility. We do not post collateral under any of these contracts as they are secured under our credit facility.
On February 28, 2011, the Predecessor novated to us fixed for floating interest rate swaps covering $225.0 million of our revolving credit facility. The fair value of these derivative instruments was a $2.9 million net asset position comprising $6.4 million of assets from interest rate derivative contracts and $3.5 million of liabilities from interest rate derivatives. These derivative contracts effectively fix the LIBOR component for $225.0 million of our credit facility at 1.9% through December 2015. As of June 30, 2011, when the interest rate derivative instruments are considered, we have an effective fixed interest rate of 4.4% comprising a 2.5% applicable margin and 1.9% fixed LIBOR rate.
On May 9, 2011 we entered into a 500 MMBtu/d natural gas collar transaction contract for the 2014 calendar year with a floor of $5.00 per MMBtu and a ceiling of $6.19 MMBtu. On the same day we entered into a 3,000 MMBtu/d natural gas collar transaction contract for the 2015 calendar year with a floor of $5.00 per MMBtu and a ceiling of $7.50 per MMBtu.
In June 2011, we entered into modifications of all our existing oil fixed price swap contracts, effectively settling those liability positions as of June 22, 2011. As part of these modifications, we paid $40.7 million to our counter parties to increase the fixed price on the contracts from their original prices at inception to market prices as of the closing dates of the modifications. The impact of the payment resulted in the recognition of a loss on commodity derivative contracts in the consolidated statement of operations of $40.7 million and is included in our net cash used in operating activities in our consolidated statement of cash flows for the six months ended June 30, 2011.
As of June 30, 2011, we held swap transaction contracts to manage our exposure to changes in the price of oil and natural gas related to our oil and natural gas production.
As of June 30, 2011, the notional volumes of our commodity derivative contracts were:
| Commodity | | Index | | July 1 - December 31, 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | |
| Oil position: | | | | | | | | | | | | | | | | | |
| Fixed price swaps | | | | | | | | | | | | | | | | | |
| Hedged volume (Bbls/d) | | WTI | | | 2,238 | | | | 2,039 | | | | 2,076 | | | | 2,090 | | | | 2,000 | |
| Average price ($/Bbl) | | | | $ | 96.40 | | | $ | 98.50 | | | $ | 98.50 | | | $ | 97.75 | | | $ | 97.10 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas position: | | | | | | | | | | | | | | | | | | | | | | |
| Fixed price swaps | | | | | | | | | | | | | | | | | | | | | | |
| Hedged volume (MMBtu/d) | | NYMEX | | | 9,045 | | | | 8,192 | | | | 7,474 | | | | 7,544 | | | | 3,398 | |
| Average price ($/MMbtu) | | | | $ | 7.15 | | | $ | 6.45 | | | $ | 6.45 | | | $ | 6.30 | | | $ | 5.52 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Collars | | | | | | | | | | | | | | | | | | | | | | |
| Hedged volume (MMBtu/d) | | | | | | | | | | | | | | | | | 500 | | | | 3,000 | |
| Average floor price ($/MMbtu) | | | | | | | | | | | | | | | | $ | 5.00 | | | $ | 5.00 | |
| Average ceiling price ($/MMbtu) | | | | | | | | | | | | | | | | $ | 6.19 | | | $ | 7.50 | |
As of December 31, 2010, the notional volumes of our derivative contracts were:
| Commodity | | Index | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | |
| Oil position: | | | | | | | | | | | | | | | | | |
| Fixed price swaps | | | | | | | | | | | | | | | | | |
| Hedged volume (Bbls/d) | | WTI | | | 2,238 | | | | 2,039 | | | | 2,076 | | | | 2,090 | | | | 2,000 | |
| Average price ($/Bbl) | | | | $ | 85.00 | | | $ | 85.25 | | | $ | 85.35 | | | $ | 84.58 | | | $ | 87.40 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas position: | | | | | | | | | | | | | | | | | | | | | | |
| Fixed price swaps | | | | | | | | | | | | | | | | | | | | | | |
| Hedged volume (MMBtu/d) | | NYMEX | | | 9,178 | | | | 8,192 | | | | 7,474 | | | | 7,544 | | | | 3,398 | |
| Average price ($/MMbtu) | | | | $ | 7.26 | | | $ | 6.45 | | | $ | 6.45 | | | $ | 6.30 | | | $ | 5.52 | |
We have elected not to designate any of our derivatives as hedging instruments. As a result, these derivative instruments are marked to fair value 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. The fair value of these derivatives were as follows as of the dates indicated:
| | | June 30, 2011 | | | December 31, 2010 | |
| | | Asset Derivative Contracts | | | Liability Derivative Contracts | | | Asset Derivative Contracts | | | Liability Derivative Contracts | |
| Commodity contracts | | $ | 15,099 | | | $ | 7,198 | | | $ | 18,047 | | | $ | 26,877 | |
| Interest rate contracts | | | 1,761 | | | | 3,535 | | | | - | | | | - | |
| | | $ | 16,860 | | | $ | 10,733 | | | $ | 18,047 | | | $ | 26,877 | |
| Commodity | | | | | | | | | | | | | | | | |
| Current | | $ | 7,141 | | | $ | 540 | | | $ | 9,027 | | | $ | 7,045 | |
| Long-term | | | 7,958 | | | | 6,658 | | | | 9,020 | | | | 19,832 | |
| | | $ | 15,099 | | | $ | 7,198 | | | $ | 18,047 | | | $ | 26,877 | |
| Interest | | | | | | | | | | | | | | | | |
| Current | | $ | - | | | $ | 3,535 | | | $ | - | | | $ | - | |
| Long-term | | | 1,761 | | | | - | | | | - | | | | - | |
| | | $ | 1,761 | | | $ | 3,535 | | | $ | - | | | $ | - | |
The following table presents the impact of derivatives and their location within our unaudited consolidated statements of operations for the three and six months period ended June 30, 2011 and June 30, 2010:
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | Partnership | | | Predecessor | | | Partnership | | | Predecessor | |
| Realized gains (losses): | | | | | | | | | | | | |
Commodity contracts (1) | | $ | (42,161 | ) | | $ | 2,071 | | | $ | (40,852 | ) | | $ | 2,913 | |
| Interest rate swaps | | | (948 | ) | | | (529 | ) | | | (1,262 | ) | | | (529 | ) |
| Total | | $ | (43,109 | ) | | $ | 1,542 | | | $ | (42,114 | ) | | $ | 2,384 | |
| Unrealized gains (losses): | | | | | | | | | | | | | | | | |
Commodity contracts (1) | | $ | 55,575 | | | $ | 44,352 | | | $ | 16,732 | | | $ | 44,933 | |
| Interest rate swaps | | | (5,079 | ) | | | (7,234 | ) | | | (4,650 | ) | | | (7,234 | ) |
| Total | | $ | 50,496 | | | $ | 37,118 | | | $ | 12,082 | | | $ | 37,699 | |
| Total gains (losses): | | | | | | | | | | | | | | | | |
| Commodity contracts | | $ | 13,414 | | | $ | 46,423 | | | $ | (24 120 | ) | | $ | 47,846 | |
Interest rate swaps (2) | | | (6,027 | ) | | | (7,763 | ) | | | (5,912 | ) | | | (7,763 | ) |
| Total | | $ | 7,387 | | | $ | 38,660 | | | $ | (30,032 | ) | | $ | 40,083 | |
| | (1) | Gains (losses) on commodity derivative contracts are located in other income (expense) in the consolidated statement of operations. |
| | | Losses on interest rate derivatives contracts are recorded as part of interest expense and is located in other income (expense) in the consolidated statement of operations. |
NOTE 5 – INCOME TAXES
We are not subject to federal income taxes, as our profits or losses are reported to the taxing authorities by the individual partners.
We are subject to Texas margin tax. We recorded a deferred tax asset of $0.3 million related to our operations located in Texas as of June 30, 2011 and December 31, 2010. The deferred tax asset is included in noncurrent assets on the consolidated balance sheet. We recognized income tax expense of $0.2 million and $0.1 million for the three and six months ended June 30, 2011.
NOTE 6 – ASSET RETIREMENT OBLIGATIONS
Changes in our asset retirement obligations for the periods indicated are presented in the following table:
| Liability for asset retirement obligation as of December 31, 2010 | | $ | 18,288 | |
| Accretion expense | | | 557 | |
| Liabilities settled | | | (65 | ) |
| Liability for asset retirement obligation as of June 30, 2011 | | $ | 18,780 | |
| | | | | |
| Current portion of asset retirment obligations | | $ | 1,783 | |
| Non-current portion of asset retirement obligations | | | 16,997 | |
| Liability for asset retirement obligation as of June 30, 2011 | | $ | 18,780 | |
NOTE 7 – LONG-TERM DEBT
Senior Secured Revolving Credit Facility
On December 22, 2010, in connection with the IPO, we entered into a credit agreement along with QRE GP, OLLC as Borrower, and a syndicate of banks (the “Credit Agreement”).
The Credit Agreement provides for a five-year, $750.0 million revolving credit facility maturing on December 22, 2015, with a borrowing base of $300.0 million as of June 30, 2011. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 each year based on an engineering report with respect to our estimated oil, natural gas and NGL reserves, which will take into account the prevailing oil, natural gas and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. Effective May 23, 2011, the lenders reaffirmed the borrowing base of $300.0 million. 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 our wholly owned subsidiary, 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%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum.
As of June 30, 2011 and December 31, 2010, we had $266.0 million and $225.0 million of borrowings outstanding and $34.0 million of borrowing availability as of June 30, 2011. For the six months ended June 30, 2011, the weighted average interest rate on the revolver was 4.0%.
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 (including a prohibition on our ability to pay distributions to our unitholders if our borrowing base usage exceeds 95%); 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 reviewed quarterly 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 from total proved reserves for the next two years and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in our 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 June 30, 2011, we were not in compliance with the total debt to EBITDAX financial covenant due to the realized loss on commodity derivatives from the modification of our existing fixed price swap contracts. However, we sought and received a consent dated August 3, 2011 from our lenders to exclude this nonrecurring item from the calculation yielding a ratio in compliance with the financial covenants as of the June 30, 2011 measurement date.
NOTE 8 — PARTNERS’ CAPITAL
Units Outstanding
On January 3, 2011, the underwriters exercised their over-allotment option in full for 2,250,000 common units issued by the Partnership at $20.00 per unit. Total net proceeds from the sale of these common units, after deducting the underwriters’ discount and structuring fees of approximately $3.0 million, were approximately $42.0 million.
As of June 30, 2011, our outstanding partnership interests consisted of 28,557,987 outstanding common units and 7,145,866 outstanding subordinated units, representing a 99.9% limited partnership interest in us, and a 0.1% general partnership interest represented by 35,729 general partner units.
Allocations of Net Income (Loss)
Net income (loss) is allocated between QRE GP and the limited partner 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. The Credit Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the Credit Agreement, occurs or would result from the cash distribution.
Our partnership agreement 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.
Distributions for the six months ended June 30, 2011 were as follows:
| | | | | Distributions | | | | | | | |
| | | | | | | | Limited Partners | | | | | | | |
| | | | | | | | | | | Affiliated | | | | | | | |
| Date Paid | | | | | | | | | | Common | | | Subordinated | | | Total | | | | |
| | | | | (In thousands, except per unit amounts) | | |
| February 11, 2011 | | December 31, 2010 | | $ | 2 | | | $ | 779 | | | $ | 506 | | | $ | 320 | | | $ | 1,607 | | | $ | 0.0448 | |
| May 13, 2011 | | March 31, 2011 | | | 15 | | | | 7,186 | | | | 4,660 | | | | 2,948 | | | | 14,809 | | | | 0.4125 | |
NOTE 9 – COMMITMENTS AND CONTINGENCIES
We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our financial position, results of operations or cash flows.
NOTE 10 – NET INCOME (LOSS) PER LIMITED PARTNER UNIT
The following sets forth the calculation of net income (loss) per limited partner unit for the following periods:
(In thousands except per share amounts)
| | | Three months ended June 30, 2011 | | | Six months ended June 30, 2011 | |
| Net income (loss) | | $ | 15,931 | | | $ | (13,417 | ) |
| Less: General partner's 0.1% interest in net income (loss) | | | 16 | | | | (13 | ) |
| Limited partners' interest in net income (loss) | | $ | 15,915 | | | $ | (13,404 | ) |
| Common unitholders' interest in net income (loss) | | $ | 12,744 | | | $ | (10,694 | ) |
| Subordinated unitholders' interest in net income (loss) | | $ | 3,171 | | | $ | (2,710 | ) |
| Net income (loss) per limited partner unit: | | | | | | | | |
| Common units (basic and diluted) | | $ | 0.44 | | | $ | (0.38 | ) |
| Subordinated units (basic and diluted) | | $ | 0.44 | | | $ | (0.38 | ) |
| Weighted average limited partner units outstanding: | | | | | | | | |
Common units (basic and diluted) (1) | | | 28,723 | | | | 28,518 | |
| Subordinated units (basic and diluted) | | | 7,146 | | | | 7,146 | |
(1) Includes 166,000 and zero weighted-average units of outstanding unvested unit-based awards for the three and six months ended June 30, 2011 (See Note 11)
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 six months ended June 30, 2011. We had 28,557,987 common units and 7,145,866 subordinated units outstanding as of June 30, 2011.
NOTE 11 – UNIT-BASED COMPENSATION
On December 22, 2010, in connection with the closing of the IPO, the board of directors of QRE GP adopted the QRE GP, LLC Long Term Incentive Plan (the “Plan”) for employees, officers, consultants and directors and consultants of QRE GP and those of 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 long-term incentive 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. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards.
During the three and six months ended June 30, 2011, we recognized compensation expense of $0.3 million and $0.6 million related to equity awards. As of June 30, 2011 we had 171,719 unit awards outstanding with unrecognized compensation expense related to nonvested restricted unit awards of $3.0 million which we expect to recognize in expense over a weighted average remaining vesting period of 2.0 years.
On January 4, 2011, we granted restricted common unit awards of 3,750 units to each of our two independent directors. These units vested immediately upon grant. The fair value of the common unit awards granted was calculated based on the closing price of our common units on the grant date, $20.20 per common unit.
On March 9, 2011, we granted restricted common unit awards of 8,985 units each to two of our named executive officers. The fair value of the common unit awards granted was calculated based on the closing price of our common units on the grant date, $22.26 per common unit, which we expect will be recognized in expense over three years.
The following table summarizes our unit-based awards for the six months ended June 30, 2011 (in units and dollars):
| | | Six months ended June 30, 2011 | |
| | | Number of Unvested Restricted Units | | | Weighted Average Grant-Date Fair Value per unit | |
| Outstanding at beginning of period | | | 148 | | | $ | 20.03 | |
Granted (1) | | | 42 | | | $ | 21.46 | |
| Forfeited | | | (8 | ) | | $ | 20.03 | |
Vested (1) (2) | | | (10 | ) | | $ | 20.15 | |
| Outstanding at end of period | | | 172 | | | $ | 20.37 | |
(1) Includes 7,500 units granted to our independent directors for services performed for us.
(2) Includes 2,750 other units vested during the period.
For the three months ended June 30, 2011 we had approximately 166,000 weighted-average restricted units outstanding.
NOTE 12 – RELATED PARTY TRANSACTIONS
In connection with the closing of the IPO, we entered into agreements with QRE GP and its affiliates. The following is a description of those agreements.
Services Agreement
On December 22, 2010, in connection with the closing of the IPO, we entered into a service agreement (the “Services Agreement”) with QRM, QRE GP and OLLC, pursuant to which QRM agreed to provide the administrative and acquisition advisory services necessary to allow QRE GP to manage, operate and grow our business. Under the Services Agreement, from the closing of the IPO through December 31, 2012, QRM is entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. After December 31, 2012, in lieu of the quarterly administrative services fee, QRE GP will reimburse QRM, on a quarterly basis, for the allocable expenses QRM incurs in its performance under the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM.
For the six months ended June 30, 2011 the Fund charged us $0.1 million in administrative service fees in accordance with the Services Agreement. For the three months ended June 30, 2011, we recognized a $0.7 million credit to our administrative service fees primarily as a result of a decrease in adjusted EBITDA due to the realized loss on derivatives buy up during the quarter. The administrative service fee is recorded in general and administrative and other in the consolidated statement of operations. The payment of the administrative service fee for each quarter is made in the subsequent quarter. For the three months and ended June 30, 2011 these settlements were $0.8 million.
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 (payable)/receivable balance during the six months ended June 30, 2011 are included below:
| Balance at December 31, 2010 | | $ | (442 | ) |
Revenues and other increases (1) | | | 52,898 | |
| Expenditures | | | (23,355 | ) |
| Settlements from the Fund | | | (17,297 | ) |
| Balance at June 30, 2011 | | $ | 11,804 | |
| | (1) | Includes $0.4 million in overhead producing credits and $1.3 million of proceeds from the sale of oil and gas leases received by the Fund on our behalf. |
Other Contributions to Partners’ Capital
Our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us for the six months ended June 30, 2011 totaled $6.5 million. QRM also incurred $0.2 million of prepaid insurance on our behalf, but not reimbursable by us for the six months ended June 30, 2011. In addition, on February 28, 2011, the Fund novated to us fixed for floating interest rate swaps covering $225.0 million of our revolving credit facility. The fair value of these derivative instruments was a $2.9 million net asset position. These transactions are recorded as other contributions in our Consolidated Statement of Changes in Partners’ Capital.
Omnibus Agreement
We entered into an omnibus agreement (the “Omnibus Agreement”) by and among QRE GP, OLLC, the Fund and QA Global GP, LLC. The Omnibus Agreement provides for, among other items, the following:
| | · | The Fund agreed to provide us, for a period of five years from the Closing Date, with the first opportunity to purchase certain oil and natural gas assets it may offer for sale that consist of at least 70% proved developed producing reserves. |
| | · | The Fund agreed to provide us, for a period of five years from the Closing Date, the first option to participate in certain of its acquisition opportunities so long as 70% of the allocated value of the acquisition is attributable to proved developed producing reserves. |
| | · | Should QA Global or any of its affiliates close any new investment fund within two years from the Closing Date, the Omnibus Agreement shall be amended to include such new investment fund as a party to the terms in the first two points above. |
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 is 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, |
| | · | the value of our commodity derivative contracts valued at SEC strip prices and discounted at 10% per annum, 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 three and six months ended June 30, 2011, no management incentive fees were earned by or paid to QRE GP.
Long–Term Incentive Plan
On December 22, 2010, in connection with the closing of the IPO, the Board of Directors of QRE GP adopted the Plan to compensate employees, officers, consultants and directors and consultants of QRE GP and those of its affiliates, including QRM, who perform services for us. As of June 30, 2011, 171,719 restricted unit awards with a grant date fair value totaling $3.5 million were outstanding under the Plan. For additional discussion regarding the Plan see Note 11.
Distributions of available cash to QRE GP and affiliates
We will generally make cash distributions to our unitholders and QRE GP pro rata, including QRE GP and our affiliates. As of June 30, 2011, QRE GP and its affiliates held 11,297,737 common units, all of the subordinated units and 35,729 general partner units. We distributed less than $0.1 million to QRE GP during the six months ended June 30, 2011.
Our Relationship with Bank of America
Don Powell, one of our independent directors, is also a director of Bank of America Corporation (“BOA”). An affiliate of BOA is a lender under our credit facility.
NOTE 13 – SUPPLEMENTAL CASH FLOW INFORMATION
| | | Partnership | | | Predecessor | |
| | | Six Months Ended June 30, 2011 | | | Six Months Ended June 30, 2010 | |
| Supplemental Cash Flow Information | | | | | | |
| Cash paid for interest | | $ | 4,602 | | | $ | 4,136 | |
| Cash paid for income taxes | | $ | - | | | $ | - | |
| Noncash Investing and Financing Activities | | | | | | | | |
| Interest rate swaps novated from the Fund | | $ | 2,875 | | | $ | - | |
| Change in accrued capital expenditures | | $ | (4,559 | ) | | $ | (5,748 | ) |
| Insurance premium financed | | $ | - | | | $ | 1,372 | |
| Additions to asset retirement obligations | | $ | - | | | $ | 10,830 | |
NOTE 14 – SUBSEQUENT EVENTS
In preparing the accompanying financial statements, we have reviewed events that have occurred after June 30, 2011, through the issuance of the financial statements.
On July 1, 2011, we granted a restricted common unit award of 1,817 units to a newly elected independent director. These units vested immediately upon grant. The fair value of the common unit award granted was calculated based on the closing price of our common units on the grant date, $20.62 per common unit.
On July 1, 2011, the Predecessor novated to the Partnership basis swaps. The basis swaps effectively limit a portion of our exposure to the differences between the NYMEX natural gas price and the price at the location where we sell our natural gas. The averages prices listed below are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these locational price differences. The fair value of these derivative instruments was $0.3 million of liability positions. These transactions will be recorded as other contributions in our consolidated statement of changes in partners’ capital in the third quarter of 2011. The following table illustrates impact of the novation upon the notional volumes of our commodity derivative contracts:
| Commodity | | Index | | July 1 - December 31 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | |
| Basis Swaps | | | | | | | | | | | | | | | | | |
| | NYMEX | | | 2,935 | | | | 2,623 | | | | 2,466 | | | | 2,466 | | | | - | |
| | | | $ | (0.16 | ) | | $ | (0.16 | ) | | $ | (0.15 | ) | | $ | (0.15 | ) | | $ | - | |
On July 13, 2011 we received an interim borrowing base redetermination under our Credit Agreement which increased the borrowing base to $330.0 million. We requested and received this interim redetermination as a result of improvements in our net derivative position due to the buyup of our existing oil fixed price swap contracts in June 2011.
On July 21 and July 22, 2011, we entered into natural gas basis swaps. The basis swaps effectively limit a portion of our exposure to the differences between the NYMEX natural gas price and the price at the location where we sell our natural gas. The averages prices listed below are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these locational price differences.
| Commodity | | Index | | | | | 2012 | | | 2013 | | | 2014 | | | 2015 | |
| Basis Swaps | | | | | | | | | | | | | | | | | |
| Hedged Volume (MMBtu/d) | | NYMEX | | | 4,400 | | | | 4,100 | | | | 3,500 | | | | 3,300 | | | | 4,300 | |
| Average price ($/MMBtu) | | | | $ | (0.11 | ) | | $ | (0.16 | ) | | $ | (0.18 | ) | | $ | (0.19 | ) | | $ | (0.17 | ) |
On July 29, 2011, we announced the board of directors of QRE GP approved a cash distribution for the second quarter of 2011 of $0.4125 per unit. On August 12, 2011 we paid $14.8 million to unitholders of record at the close of business on August 8, 2011.
You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II—Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 (the “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 Annual Report and in Part II—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 own and exploit producing oil and natural gas properties in North America. Certain of the Predecessor’s subsidiary limited partnerships (collectively known as the “Fund”), comprise 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”).
On December 22, 2010, in connection with our IPO, the Fund conveyed to us oil and natural gas producing properties located in Alabama, Arkansas, Kansas, Louisiana, New Mexico, Oklahoma, Texas and an 8.05% overriding oil royalty interest in Florida. Our average daily oil and natural gas production for each of the three and six months ended June 30, 2011 was 5.4 MMBoe/d.
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 exploration 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. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.
Our discussion and analysis of the results of operations below includes a comparison of the three months ended June 30, 2011 to the three months ended March 31, 2011. We believe such a comparison will enable the reader to assess material changes in our results of operations in calendar year 2011. Our first interim financial statements in calendar year 2012 will discuss material changes in our results of operations from three months ended March 31, 2012 to the corresponding three months ended March 31, 2011. Interim filings subsequent to the calendar year 2011 filings will not compare intra-year three month periods.
Results of Operations
The table below summarizes certain of the results of operations attributable to the Partnership and the Predecessor for the periods indicated. Because the historical results of the Predecessor include results for both the properties conveyed to us in connection with our IPO and properties retained by the Predecessor, we do not consider these historical results of the Predecessor for operations and period-to-period comparisons of our results as indicative of our future results. Nevertheless, they are presented here to provide a possible context for our current operations. These results are presented for illustrative purposes only and are not indicative of future results of the Partnership. The prior year Predecessor data reflects only those properties that were owned by the Predecessor at that point.
| | | Partnership | | | Predecessor | |
| | | Three Months Ended March 31, | | | Three Months Ended June 30, | | | Six Months Ended June 30, | | | Three Months Ended June 30, | | | Six Months Ended June 30, | |
| | | 2011 | | | 2011 | | | 2011 | | | 2010 | | | 2010 | |
| Revenues: | | | | | | | | | | | | | | | |
| Oil sales | | $ | 23,517 | | | $ | 23,726 | | | $ | 47,243 | | | $ | 36,012 | | | $ | 61,077 | |
| Natural gas sales | | | 5,262 | | | | 5,483 | | | | 10,745 | | | | 13,982 | | | | 20,297 | |
| NGLs sales | | | 1,790 | | | | 2,170 | | | | 3,960 | | | | 3,023 | | | | 5,483 | |
| Processing and other | | | 198 | | | | 274 | | | | 472 | | | | 2,342 | | | | 4,135 | |
| Total Revenue | | | 30,767 | | | | 31,653 | | | | 62,420 | | | | 55,359 | | | | 90,992 | |
| Operating Expenses: | | | | | | | | | | | | | | | | | | | | |
| Lease operating expenses | | | 6,274 | | | | 6,533 | | | | 12,807 | | | | 17,625 | | | | 28,599 | |
| Production and other taxes | | | 1,978 | | | | 2,155 | | | | 4,133 | | | | 4,119 | | | | 6,098 | |
| Processing and transportation | | | 522 | | | | 89 | | | | 611 | | | | 1,198 | | | | 2,560 | |
| Total production expenses | | | 8,774 | | | | 8,777 | | | | 17,551 | | | | 22,942 | | | | 37,257 | |
| Depreciation, depletion and amortization | | | 8,575 | | | | 8,636 | | | | 17,211 | | | | 14,903 | | | | 19,241 | |
| Accretion of asset retirement obligations | | | 267 | | | | 290 | | | | 557 | | | | 782 | | | | 1,455 | |
| Management fees | | | - | | | | - | | | | - | | | | 2,855 | | | | 4,970 | |
| Acquisition evaluation costs | | | - | | | | - | | | | - | | | | 1,042 | | | | 1,042 | |
| General and administrative and other | | | 3,433 | | | | 3,344 | | | | 6,777 | | | | 5,241 | | | | 10,630 | |
| Bargain purchase gain | | | - | | | | - | | | | - | | | | (1,020 | ) | | | (1,020 | ) |
| Total operating expenses | | | 21,049 | | | | 21,047 | | | | 42,096 | | | | 46,745 | | | | 73,575 | |
| Operating income | | | 9,718 | | | | 10,606 | | | | 20,324 | | | | 8,614 | | | | 17,417 | |
| Other (expense) income: | | | | | | | | | | | | | | | | | | | | |
| Equity in earnings of Ute Energy, LLC | | | - | | | | - | | | | - | | | | 646 | | | | 708 | |
| Realized gains (losses) on commodity derivative instruments | | | 1,309 | | | | (42,161 | ) | | | (40,852 | ) | | | 2,071 | | | | 2,913 | |
| Unrealized (losses) gains on commodity derivative instruments | | | (38,843 | ) | | | 55,575 | | | | 16,732 | | | | 44,352 | | | | 44,933 | |
| Interest expense | | | (1,676 | ) | | | (7,854 | ) | | | (9,530 | ) | | | (12,015 | ) | | | (12,884 | ) |
| Other expense | | | - | | | | - | | | | - | | | | (166 | ) | | | (409 | ) |
| Total other (expense) income, net | | | (39,210 | ) | | | 5,560 | | | | (33,650 | ) | | | 34,888 | | | | 35,261 | |
| (Loss) income before income taxes | | | (29,492 | ) | | | 16,166 | | | | (13,326 | ) | | | 43,502 | | | | 52,678 | |
| Income tax benefit (expense), net | | | 144 | | | | (235 | ) | | | (91 | ) | | | (211 | ) | | | (211 | ) |
| Net (loss) income | | $ | (29,348 | ) | | $ | 15,931 | | | $ | (13,417 | ) | | $ | 43,291 | | | $ | 52,467 | |
| Production data: | | | | | | | | | | | | | | | | | | | | |
| Oil (MBbls) | | | 246 | | | | 254 | | | | 500 | | | | 505 | | | | 847 | |
| Natural gas (MMcf) | | | 1,253 | | | | 1,167 | | | | 2,420 | | | | 3,402 | | | | 4,506 | |
| Natural gas liquids (MBbls) | | | 38 | | | | 40 | | | | 78 | | | | 70 | | | | 119 | |
| Total (Mboe) | | | 493 | | | | 489 | | | | 981 | | | | 1,142 | | | | 1,717 | |
| Average Net Production (Boe/d) | | | 5,473 | | | | 5,368 | | | | 5,422 | | | | 12,549 | | | | 9,486 | |
| Average sales price per unit: | | | | | | | | | | | | | | | | | | | | |
| Oil (per Bbl) | | $ | 95.60 | | | $ | 93.41 | | | $ | 94.49 | | | $ | 71.31 | | | $ | 72.11 | |
| Natural gas (per Mcf) | | $ | 4.20 | | | $ | 4.70 | | | $ | 4.44 | | | $ | 4.11 | | | $ | 4.50 | |
| NGLs (per Bbl) | | $ | 47.11 | | | $ | 54.25 | | | $ | 50.77 | | | $ | 43.19 | | | $ | 46.08 | |
| Average unit cost per Boe: | | | | | | | | | | | | | | | | | | | | |
| Lease operating expense | | $ | 12.74 | | | $ | 13.37 | | | $ | 13.05 | | | $ | 15.43 | | | $ | 16.66 | |
| Production and other taxes | | $ | 4.02 | | | $ | 4.41 | | | $ | 4.21 | | | $ | 3.61 | | | $ | 3.55 | |
| Management fees | | $ | - | | | $ | - | | | $ | - | | | $ | 2.50 | | | $ | 2.89 | |
| Depreciation, depletion and amortization | | $ | 17.41 | | | $ | 17.68 | | | $ | 17.54 | | | $ | 13.05 | | | $ | 11.21 | |
| General and administrative expenses | | $ | 6.96 | | | $ | 6.85 | | | $ | 6.91 | | | $ | 4.59 | | | $ | 6.19 | |
Factors Affecting the Comparability of the Historical Financial Results of Us and Our Predecessor
The comparability of our results for the three and six months ended June 30, 2011 and the Predecessor’s results for the three and six months ended June 30, 2010 is impacted as follows:
| | · | Our results for the three and six months ended June 30, 2011 include additional operating results from certain properties that were contributed to us in connection with the Predecessor’s Denbury acquisition, which occurred in May 2010; and therefore not part of our Predecessor’s operating results for the entire three and six months ended June 30, 2010. |
| | · | Our results for the three and six months ended June 30, 2011 do not include the operating results of certain properties owned by the Predecessor during the three and six month periods ended June 30, 2010 that were not contributed to us. |
Accordingly, we have presented our comparison of our results for the three months ended June 30, 2011 against our results for the three months ended March 31, 2011 below.
Partnership’s Results of Operations
Results for the Three Months Ended June 30, 2011 Compared to the Three Months Ended March 31, 2011
We recorded net income of $15.9 million for the three months ended June 30, 2011 compared to a net loss of $29.3 million for the three months ended March 31, 2011. The following discussion summarizes key items of comparison and their related change.
Sales Revenues. Sales revenues increased $0.9 million to $31.7 million for the three months ended June 30, 2011 compared to $30.8 million for the three months ended March 31, 2011. The increase was primarily due to the increase in our oil and NGL volumes, partially offset by the decrease in our natural gas production which contributed a $0.5 million increase in revenues for the second quarter as compared to the first quarter 2011. Commodity prices contributed a $0.3 million increase in revenue quarter over quarter. Also contributing to the increase in sales revenue was an increase of $0.1 million in processing income.
Certain out-of-period adjustments to our revenues were disclosed in Note 2 to our consolidated financial statements. These out-of-period adjustments had the effect of reversing approximately $2.0 million in revenue from commodity sales in the three months ended June 30, 2011 that had been over-reported in the three months ended March 31, 2011. Had this out-of-period adjustment not been recorded, our revenue for the three months ended June 30, 2011 would have been $33.7 million, or an increase of $2.0 million from that which was reported in the three months ended June 30, 2011, or an increase of $4.9 million from the $28.8 million that would have been reported in the three months ended March 31, 2011.
The $4.9 million increase in revenue after consideration of the out-of-period adjustments was primarily due to the increase in our oil volumes, partially offset by the decrease in our NGL and natural gas production which contributed a $3.4 million increase in revenues for the second quarter as compared to the first quarter 2011 due to our successful workover projects. Commodity prices contributed a $1.5 million increase in revenue quarter over quarter.
Effects of Commodity Derivative Contracts. On June 22, 2011 we entered into modifications of all our existing oil fixed priced swap derivative contracts with cash payments to counterparties recognized as a realized loss of $40.7 million. Concurrent with this cash payment, we also recognized an offsetting unrealized gain of $40.7 million due to the modification of the fixed prices up to market price on the trade date. The modification increased the weighted average prices on our fixed price oil swap contracts by 14% from $85.55 per Bbl to $97.78 per Bbl for the second half of 2011 through 2015.
Our realized losses on commodity derivatives exclusive of the modifications above were $1.5 million for the three months ended June 30, 2011 compared to a $1.3 million gain for the three months ended March 31, 2011. The increase in losses quarter over quarter is primarily due to payments to settle oil contracts.
Our unrealized gains on commodity derivatives exclusive of the modifications were $14.9 million for the three months ended June 30, 2011 compared to a $38.8 million unrealized loss for the three months ended March 31, 2011. The increase in unrealized gains quarter over quarter is primarily due to unrealized gains on oil contracts.
Production Expenses. Our production expense remained flat at $8.8 million for the three months ended March 31, 2011 and June 30, 2011.
Certain out-of-period adjustments to our production expenses are disclosed in Note 2 to our consolidated financial statements. These out-of-period adjustments had the effect of reversing approximately $0.6 million in production expenses in the three months ended June 30, 2011 that had been over-reported in the three months ended March 31, 2011. Had this out-of-period adjustment not been recorded, our production expense for the three months ended June 30, 2011 would have been $9.4 million, or an increase of $0.6 million from that which was reported in the three months ended June 30, 2011, or an increase of $1.3 million from the $8.1 million that would have been expensed in the three months ended March 31, 2011. The increase in production expenses after consideration of the out-of-period adjustments is primarily due to an increase in lease operating expenses of $1.3 million quarter over quarter comprising a $1.1 million increase from higher average cost per unit based on revised estimates during the three months ended June 30, 2011 and $0.2 million as a result of increased production.
Depreciation, Depletion and Amortization Expenses. For the three months ended June 30, 2011 and March 31, 2011, our depreciation, depletion and amortization expense was $8.6 million. On a per unit basis, we increased depreciation, depletion and amortization expense by $0.27 to $17.68 per Boe in the second quarter versus $17.41 per Boe in the first quarter.
Certain out-of-period adjustments to our depletion expenses are disclosed in Note 2 to our consolidated financial statements. These out-of-period adjustments had the effect of reversing approximately $0.2 million in depletion expense in the three months ended June 30, 2011 that had been over-reported in the three months ended March 31, 2011. Had this out-of-period adjustment not been recorded, our depreciation, depletion and amortization expense for the three months ended June 30, 2011 would have been $8.8 million, or an increase of $0.2 million from that which was reported in the three ended months June 30, 2011, or an increase of $0.4 million from the $8.4 million that would have been expensed in the three months ended March 31, 2011. The increase in depreciation, depletion and amortization expense after consideration of the out-of-period adjustment is primarily due to an increase in production quarter over quarter.
General and Administrative and Other Expenses. Our general and administrative and other expenses decreased $0.1 million to $3.3 million, or $6.85 per Boe produced, during the three months ended June 30, 2011 compared to $3.4 million, or $6.96 per Boe during the three months ended March 31, 2011.
Interest Expense, net. Net interest expense was $7.9 million for the three months ended June 30, 2011 for an increase of $6.2 million from $1.7 million for the three months ended March 31, 2011. The increase in interest expense was primarily due to losses on interest rate derivatives of $6.0 million.
Results for the Six Months Ended June 30, 2011.
We recorded a net loss of $13.4 million for the six months ended June 30, 2011.
Sales Revenues. Sales revenues of $62.4 million for the six months ended June 30, 2011 consisted of oil sales of $47.2 million, natural gas sales of $10.7 million and NGL sales of $4.0 million. Oil sales volumes were 500 MBbls and the average sales price was $94.49 per Bbl. Natural gas sales volumes were 2,420 MMcf and the average sales price was $4.44 per Mcf. NGL sales volumes were 78 MBbls and the average sales price was $50.77 per Bbl. Production for the six months ended June 30, 2011 was 5.4 MBoe/d.
Effects of Commodity Derivative Contracts. On June 22, 2011 we entered into modifications of all our existing oil fixed priced swap derivative contracts with cash payments to counterparties recognized as a realized loss of $40.7 million. Concurrent with this cash payment, we also recognized an offsetting unrealized gain of $40.7 million due to the modification of the fixed prices up to market price on the trade date. The modification increased the weighted average prices on our fixed price oil swap contracts by 14% from $85.55 per Bbl to $97.78 per Bbl for the second half of 2011 through 2015.
Our realized losses on commodity derivatives exclusive of the modifications above were $0.2 million for the six months ended June 30, 2011 due to oil settlements partially offset by natural gas settlements.
Our unrealized losses on commodity derivatives exclusive of the modifications above were $24.0 million million for the six months ended June 30, 2011 primarily due to unrealized losses on oil contracts partially offset by unrealized gains on natural gas contracts.
Production Expenses. During the six months ended June 30, 2011, our production expenses were $17.6 million, consisting of $12.8 million in lease operating expenses, or $13.05 per Boe, and $4.1 million in production and other taxes, or $4.21 per Boe.
Depreciation, Depletion and Amortization Expenses. For the six months ended June 30, 2011, our depreciation, depletion and amortization expenses were $17.2 million, or $17.54 per Boe.
General and Administrative and Other Expenses. For the six months ended June 30, 2011, our general and administrative and other expenses were $6.8 million, or $6.91 per Boe.
Interest Expense, net. Net interest expense was $9.5 million for the six months ended June 30, 2011 comprising $3.6 million in interest for the revolver balance and $5.9 million related to interest rate derivatives.
Predecessor Results of Operations for Three Months Ended June 30, 2010
Sales Revenues. Sales revenues were $55.4 million for the three months ended June 30, 2010, consisting of oil sales of $36.0 million, natural gas sales of $14.0 million and NGL sales of $3.0 million. Oil sales volumes were 505 MBbls and the average sales price was $71.31 per Bbl. Natural gas volumes were 3,402 MMcf and the average sale price was $4.11 per Mcf. NGL volumes were 70 MBbls and the average sales price was $43.19 per Bbl. Production for the three months ended June 30, 2010 was 12.5 MBoe/d. In addition, processing and other revenues were $2.4 million generated primarily from sulfur revenue.
Effects of Commodity Derivative Contracts. Due to decreases in oil and natural gas prices, our Predecessor recorded a net gain from our commodity derivatives program during the period of $46.4 million, composed of a realized gain of $2.1 million and an unrealized gain of $44.3 million.
Production Expenses. Our Predecessor’s production expenses were $22.9 million, consisting of $17.6 million in lease operating expenses or $15.43 per Boe and $4.1 million in production and other taxes or $3.61 per Boe.
Depreciation, Depletion and Amortization Expenses. Our Predecessor’s depreciation, depletion and amortization expenses were $14.9 million, or $13.05 per Boe produced, during the period.
Management Fee. Our Predecessor’s management fees were $2.9 million for the three months ended June 30, 2010.
General and Administrative and Other Expenses. Our Predecessor’s general and administrative and other expenses were $5.2 million, or $4.59 per Boe for the three months ended June 30, 2010.
Interest Expense, net. Interest expense was $12.0 million for the three months ended June 30, 2010 which included deferred financing cost amortization of $1.1 million.
Predecessor Results of Operations for the Six Months Ended June 30, 2010
Sales Revenues. Sales revenues were $91.0 million for the six months ended June 30, 2010, consisting of oil sales of $61.1 million, natural gas sales of $20.3 million and NGL sales of $5.5 million. Oil sales volumes were 847 MBbls and the average sales price was $72.11 per Bbl. Natural gas volumes were 4,506 MMcf and the average sale price was $4.50 per Mcf. NGL volumes were 119 MBbls and the average sales price was $46.08 per Bbl. Production for the six months ended June 30, 2010 was 9.5 MBoe/d. In addition processing and other revenues were $4.1 million generated primarily from sulfur revenue.
Effects of Commodity Derivative Contracts. Due to decreases in oil and natural gas prices, our Predecessor recorded a net gain from our commodity derivatives program during the period of $47.8 million, composed of a realized gain of $2.9 million and an unrealized gain of $44.9 million.
Production Expenses. Our Predecessor’s production expenses were $37.3 million, consisting of $28.6 million in lease operating expenses, or $16.66 per Boe, and $6.1 million in production and other taxes, or $3.55 per Boe.
Depreciation, Depletion and Amortization Expenses. Our Predecessor’s depreciation, depletion and amortization expenses were $19.2 million, or $11.21 per Boe produced, during the period.
Management Fee. Our Predecessor’s management fees were $5.0 million for the six months ended June 30, 2010.
General and Administrative and Other Expenses. Our Predecessor’s general and administrative and other expenses were $10.6 million, or $6.19 per Boe, for the six months ended June 30, 2010.
Interest Expense, net. Interest expense was $12.9 million for the six months ended June 30, 2010 which included deferred financing cost amortization of $1.3 million.
Liquidity and Capital Resources
Our cash flow used in operating activities for the six months ended June 30, 2011, was $21.2 million, which included a payment of $40.7 million to increase the fixed price we will receive in future periods under all our existing oil fixed-price swap derivative contracts effectively settling a portion of those liabilities as of June 22, 2011. Funding for the payment to modify these contracts was obtained from borrowings under our credit facility.
Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our credit facility. 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, 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.
As of June 30, 2011, our liquidity of $34.2 million consisted of $0.2 million of available cash and $34.0 million of availability under our credit facility. 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. As of June 30, 2011, we had borrowing capacity of $34.0 million ($300.0 million borrowing base less $266.0 million of outstanding borrowing) under our credit facility. The borrowing base will be redetermined as of May 1 and November 1 of each year, beginning with May 1, 2011, by the administrative agent of our credit facility. Effective May 23, 2011, the lenders reaffirmed the borrowing base of $300.0 million. In addition, we may request additional capacity for acquisitions of a minimum of the lesser of $50.0 million or ten percent of then-existing borrowing base. On July 13, 2011 we received an interim borrowing base redetermination for our Credit Agreement which increased the borrowing base to $330.0 million. We requested and received this interim redetermination as a result of improvements in our net derivative position due to the buyup of our existing oil fixed price swap contracts in June 2011.
A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands. As of June 30, 2011, we had no letters of credit outstanding.
We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.4125 per unit per quarter ($1.65 per common unit on an annualized basis). As of June 30, 2011, such annual minimum amounts payable to unitholders approximated $59.2 million. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations above maintenance capital expenditures. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures.
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 June 30, 2011, we had a positive working capital balance of $18.0 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 to maintain our distributions per unit. For 2011, we have estimated our maintenance capital expenditures to be approximately $12.5 million. During the six months ended June 30, 2011, we expended $7.2 million of capital expenditures.
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 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. 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 may make acquisitions during the fiscal year ending December 31, 2011, including potential acquisitions of producing properties from the Fund, we have not estimated any growth capital expenditures related to acquisitions, 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 are 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 new credit facility will exceed our planned capital expenditures and other cash requirements for 2011. 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.
For the six months ended June 30, 2010, our Predecessor’s expenditures were $904.2 million, comprising $891.9 million of acquisition related expenditures, $11.7 million of capital expenditures and $0.6 million of other additions to property and equipment. The Predecessor’s acquisition related expenditures included $888.8 million of payments for the Denbury Acquisition and also $3.1 million of payments for surface acquisitions in a portion of the Jay field.
Credit Agreement
The Credit Agreement provides for a five-year, $750.0 million revolving credit facility, with a current borrowing base of $300 million as of June 30, 2011. The borrowing base will be subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, natural gas and NGL reserves, which will take into account the prevailing oil, natural gas and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. On July 13, 2011 we received an interim borrowing base redetermination for our Credit Agreement which increased the borrowing base to $330.0 million. 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 our wholly owned subsidiary, 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%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum.
The Credit Agreement requires us to maintain a leverage ratio (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 (including a prohibition on our ability to pay distribution to our unitholders if our borrowing base usage exceeds 95%); 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 reviewed quarterly 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 from total proved reserves for the next two years and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in our 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 June 30, 2011, we were not in compliance with the total debt to EBITDAX financial covenant due to the realized loss on commodity derivatives from the modification of our existing fixed price swap contracts. However, we sought and received a consent dated August 3, 2011 from our lenders to exclude this nonrecurring item from the calculation yielding a ratio in compliance with the financial covenants as of the June 30, 2011 measurement date.
As of June 30, 2011, we had $266.0 million of outstanding borrowings under the facility.
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.
Cash Flows
Cash flows provided (used) by type of activity were as follows for the periods indicated:
| | | Partnership | | | Predecessor | |
| | | Six Months Ended June 30, | | | Six Months Ended June 30, | |
| | | 2011 | | | 2010 | |
| Net Cash provided by (used in): | | | | | | |
| Operating activities | | $ | (21,203 | ) | | $ | 15,858 | |
| Investing activities | | | (5,888 | ) | | | (904,215 | ) |
| Financing activities | | | 25,048 | | | | 890,405 | |
Operating Activities
Our cash flow used in operating activities for the six months ended June 30, 2011 was $21.2 million, comprising a one-time payment of $40.7 million to modify our fixed price swap derivative contracts partially offset by $19.5 of other net operating cash inflows primarily due to favorable operating margins.
Investing Activities
Our cash flow used in investing activities for the six months ended June 30, 2011 was $5.9 million comprising $7.2 million of payments made for additions to oil and natural gas properties partially offset by $1.3 million in proceeds from the sale of oil and gas properties.
Financing Activities
Our cash flow from financing activities for the six months ended June 30, 2011 was $25.0 million, comprising cash inflows of $83.6 million primarily due to contributions from the underwriters’ exercise of their over-allotment option, in connection with the IPO, of and proceeds from bank borrowings to fund the $40.7 million payment to modify our oil fixed price swap derivative contracts. These cash inflows were partially offset by $58.6 million cash outflows primarily due to distributions to the Fund and public unitholders.
Capital Requirements
We currently estimate maintenance capital expenditures to be approximately $12.5 million to develop our oil and natural gas properties during 2011.
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 2011 through a combination of cash, borrowings under our credit facility, and the issuance of equity securities.
Contractual Obligations
There have been no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements. Our level of capital expenditures will vary in the future periods depending on the success we experience in our acquisition, development and exploration 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 June 30, 2011, 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 accounting principles generally accepted in the United States. 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 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, natural gas and natural gas liquids prices by reducing the risk of price volatility and the effect it could have on our operations. The type 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 for the next 12 to 60 months. 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 Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Item 1. Consolidated Financial Statements (Unaudited)—Note 4, “Derivatives Activities” for additional information.
We are also exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Periodically, we may look to utilize interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At June 30, 2011, we did have open positions that converted our variable interest rate debt to fixed interest rates on $225.0 million of our outstanding debt. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves. As of June 30, 2011, a hypothetical change of 100 basis points in the underlying interest rate of our variable rate debt, after taking into account our interest rate swaps, would impact our annual interest expense by $0.4 million.
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. See Part I - Item 1. Consolidated Financial Statements (Unaudited)—Note 4, “Derivatives Activities” for more details.
Material Weaknesses in Internal Control over Financial Reporting.
Prior to the completion of our IPO, our Predecessor was a private partnership with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address internal control over financial reporting. Our control environment and control activities are the same as our Predecessor. As previously discussed in Part II - Item 9A. “Controls and Procedures” of our Annual Report, we reported material weaknesses in our overall control environment, as well as numerous material weaknesses at various control activity levels. These material weaknesses continue to exist as of June 30, 2011, the end of the period covered by this report.
Evaluation of Disclosure Controls and Procedures.
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2011. 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. In light of the previously identified material weaknesses described in our Annual Report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of June 30, 2011.
We have begun the process of implementing processes to remediate the material weakness in our internal control over financial reporting, although we are in the early phases of our review and do not expect to complete our review until the fourth quarter of 2011. We cannot predict the outcome of our review at this time. During the course of the review and remediation process, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weaknesses previously identified. Each of the material weaknesses described in Part II - Item 9A, “Controls and Procedures” of our Annual Report, could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our interim consolidated financial statement that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses previously disclosed in our 2010 Annual Report on Form 10-K or avoid potential future material weaknesses.
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 June 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II – OTHER INFORMATION
There have been no material changes to our legal proceedings set forth in Part I-Item 3 “-Legal Proceedings” included in our Annual Report. We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our financial position, results of operations or cash flows for the six months period ended June 30, 2011.
The following risk factors should be read in conjunction with our risk factors described in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion of certain oil and natural gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production. This process is typically regulated by state oil and natural gas agencies. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents on regulating requirements for companies that plan to conduct hydraulic fracturing using diesel. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing a number of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy and the U.S. Government Accountability Office are studying different aspects of how hydraulic fracturing might adversely affect the environment, and the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal land, which, if adopted, would affect any of our operations on federal lands. A committee of the United States House of Representatives also has conducted an investigation of hydraulic fracturing practices. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or under newly established legislation. In addition, for the second consecutive session, the federal Congress is considering two companion bills, known as the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act,” that would repeal an exemption in the federal Safe Drinking Water Act for the underground injection of hydraulic fracturing fluids other than diesel near drinking water sources. Moreover, some states, including Texas, have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. On June 17, 2011, Texas signed into law a bill that requires, subject to certain trade secret protections, disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. Adoption of legislation or any implementing regulations placing restrictions on hydraulic fracturing activities could increase our costs of compliance with potentially applicable permitting, financial assurance, construction, monitoring, reporting and plugging and abandonment requirements, impose operational delays and make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced. In addition, if hydraulic fracturing is regulated at the federal level, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements and attendant permitting delays and potential increases in costs. Some or all of these developments could have a material adverse effect on our business, financial condition and results of operations.
Recently proposed rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs, which may be significant.
On July 28, 2011, the U.S. Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.
None.
None.
None.
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.
| Exhibit | | | | | | |
| | | | | | |
| 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 | | | | — | | Agreement of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.2 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010). |
| 3.3 | | | | — | | 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). |
| 3.4 | | | | — | | 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 | | | | — | | Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.5 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010). |
| 3.6 | | | | — | | First Amendment to Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.6 of the Partnership’s Registration Statement on Form S-1/A (File No. 333-169664) filed on November 26, 2010). |
| 3.7 | | | | — | | 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). |
| | * | | — | | Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934 |
| | * | | — | | Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934 |
| | ** | | — | | 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. |
| | ** | | — | | 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 |
_____________
* Filed as an exhibit to this Quarterly Report on Form 10-Q.
** Furnished as an exhibit to this Quarterly Report on Form 10-Q.
# Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under those sections.
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.
| | QR ENERGY, LP |
| | | |
| | By: | QRE GP, LLC, |
| | | its General Partner |
| | | |
| Dated: August 15, 2011 | By: | /s/ Alan L. Smith |
| | | Alan L. Smith |
| | | Chief Executive Officer and Director |
| | | |
| Dated: August 15, 2011 | By: | /s/ Cedric W. Burgher |
| | | Cedric W. Burgher |
| | | Chief Financial Officer |
