UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the quarterly period ended March 31, 2012
Commission File No.: 1-35374
Mid-Con Energy Partners, LP
(Exact name of registrant as specified in its charter)
2501 North Harwood Street, Suite 2410
Dallas, Texas 75201
(Address of principal executive offices and zip code)
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
As of May 6, 2012, the registrant had 18,149,561 common units and general partner units outstanding.
This Quarterly Report on Form 10-Q (Form 10-Q) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934 (each a forwardlooking statement). These forwardlooking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:
All of these types of statements, other than statements of historical fact included in this Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Item 1. Financial Statements, Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations and other items within this Form 10-Q. In some cases, forward-looking statements can be identified by terminology such as may, will, could, should, expect, plan, project, intend, anticipate, believe, estimate, predict, potential, pursue, target, continue, goal, forecast, guidance, continue, might, scheduled and the negative of such terms or other comparable terminology.
The forward-looking statements contained in this Form 10-Q are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, managements assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this Form 10-Q are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the Risk Factors section included in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011 (Annual Report). This document is available through our web site, www.midconenergypartners.com or through the Securities and Exchange Commissions (SEC) Electronic Data Gathering and Analysis Retrieval System at http://www.sec.gov. All forward-looking statements speak only as of the date made, and other than as required by law. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
INFORMATION AVAILABLE ON OUR WEBSITE
We make available, free of charge, on our website (www.midconenergypartners.com) copies of our Annual Reports, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Governance Guidelines, Partnership Agreement and the written charter of our Audit Committee are also available on our website, and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report.
We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.
Mid-Con Energy Partners, LP and subsidiaries
(in thousands, except number of units)
See accompanying notes to consolidated financial statements
Mid-Con Energy Partners, LP and subsidiaries
(in thousands, except per unit data)
See accompanying notes to consolidated financial statements
Mid-Con Energy Partners, LP and subsidiaries
See accompanying notes to consolidated financial statements
Mid-Con Energy Partners, LP and subsidiaries
Mid-Con Energy Partners, LP
Nature of Operations
Mid-Con Energy Partners, LP (we, our, or us) is a publicly held Delaware limited partnership that engages in the acquisition, exploitation and development of producing oil and natural gas properties in North America, with a focus on the Mid-Continent region of the United States. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company.
In December 2011, Mid-Con Energy I, LLC and Mid-Con Energy II, LLC (our predecessor), merged into our wholly owned subsidiary, Mid-Con Energy Properties, LLC.
Basis of Presentation
Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted in this Form 10-Q. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10K for the year ended December 31, 2011.
All intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Unaudited Condensed Consolidated Financial Statements, all dollar and unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated.
We have a long-term incentive program (the Plan) for employees, officers, consultants and directors of our general partner and affiliates, including Mid-Con Energy Operating, Inc. (Mid-Con Energy Operating), who perform services for us. The Plan allows for the award of unit options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights granted with phantom units, or other type of award. As of March 31, 2012, the Plan permits the grant of awards covering an aggregate of 1,764,000 units.
In January 2012, we issued 125,000 unrestricted common units (URUs) to employees, officers, directors and consultants of our general partner and affiliates. Also, in January 2012, we issued 24,561 restricted common units (RUs) that have a three-year vesting period. The fair market value of both the URUs and RUs was based on the closing price of our common units at the date of the awards, which was $20.90 per unit. The RUs are subject to forfeiture and we assume a 10% forfeiture rate for the RUs to estimate our equity-based compensation expense. These costs are reported as a component of general and administrative expense in our unaudited condensed consolidated statements of operations. The equity-based compensation expense for the three months ended March 31, 2012 was $2.7 million. There was no equity-based compensation expense for the three months ended March 31, 2011.
Our risk management program is intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flows. Accordingly, we utilize derivative financial instruments to manage our exposure to commodity price fluctuations and fluctuations in location differences between published index prices and the NYMEX futures prices. Our policies do not permit the use of derivatives for speculative purposes.
We have elected not to designate any of our positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts as Unrealized losses on derivatives, net in our unaudited condensed consolidated statements of operations. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, we present the fair value of derivative financial instruments on a net basis.
As of March 31, 2012, we had the following commodity derivative open positions:
The fair value and location of our derivatives in our condensed consolidated balance sheets was as follows:
The following table presents the impact of derivative financial instruments and their location within the unaudited condensed consolidated statements of operations:
Fair Value of Financial Instruments
The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts payable and derivative financial instruments approximate their fair values. The carrying amount of long-term debt under our credit facility approximates fair value because the credit facilitys variable interest rate resets frequently and approximates current market rates available to us.
We account for our oil and gas commodity derivatives at fair value. The fair value of our derivative financial instruments is determined utilizing NYMEX closing prices for the contract period.
Fair Value Measurements
Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy that is intended to increase consistency and comparability in fair value measurements and related disclosures. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Our assets and liabilities recorded in the balance sheet are categorized based on the inputs to the valuation technique as follows:
Level 1Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.
Level 2Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.
Level 3Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect managements own assumptions about the assumptions a market participant would use in pricing the asset or liability.
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value as of March 31, 2012 and December 31, 2011:
Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs during the three months ended March 31, 2012.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
We estimate the fair value of the asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note 5 for a summary of changes in asset retirement obligations.
We review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the asset exceeds its estimated fair value. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs.
Asset retirement obligations (ARO) are recorded as a liability at their estimated present value at the various assets inception, with the offsetting charge to oil and gas properties. Periodic accretion of the discounted estimated liability is recorded in the statement of operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets based on proved developed reserves.
Our AROs represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their production lives, in accordance with applicable state laws. We determine our asset retirement obligations by calculating the present value of estimated cash flow related to the liability. Each year we review, and to the extent necessary, revise our asset retirement obligation estimates.
Changes in our asset retirement obligations for the periods indicated are presented in the following table:
As of March 31, 2012 and December 31, 2011, $2.2 million and $1.9 million, respectively, of our ARO is classified as long-term and is reported as Asset retirement obligation in our unaudited condensed consolidated balance sheets.
As of March 31, 2012, our credit facility consists of a $250.0 million senior secured revolving facility that expires in December 2016. Borrowings under the facility are secured by liens on not less than 80% of our assets and the assets of our subsidiary. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. The facility requires us and our subsidiary to maintain a leverage ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0. As of March 31, 2012 and December 31, 2011, we were in compliance with all debt covenants.
Borrowings under the credit agreement bear interest at a floating rate based on, at our election: (i) the greater of the prime rate of the Royal Bank of Canada, the federal funds effective rate plus 0.50%, or the one month adjusted LIBOR plus 1.0%, all of which is subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. At March 31, 2012, the weighted average effective interest rate was 2.5%. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.
On April 23, 2012, our borrowing base was increased to $100.0 million and Wells Fargo Bank, N.A. was added as an additional lender. No other material terms of the credit facility were amended. Borrowings under the facility may not exceed our current borrowing base of $100.0 million. The borrowing base is determined by our lenders based on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other matters that may vary. The borrowing base is subject to scheduled redeterminations on or about April 30 and October 31 of each year with an additional redetermination during the period between each scheduled borrowing base determination, either at our request or at the request of the lenders. An additional borrowing base redetermination may be made at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract.
At March 31, 2012, we had $42.0 million in indebtedness outstanding under the facility.
We are party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our financial position, results of operations or cash flows.
At March 31, 2012, owners equity consisted of 17,789,561 common units, representing approximately a 98% limited partnership interest in us.
On January 25, 2012, the board of directors of our general partner declared a quarterly cash distribution for the fourth quarter of 2011 of $0.057 per unit. The distribution represented a proration of our initial quarterly distribution of $0.475 per unit for the period from December 21, 2011 through December 31, 2011. The aggregate distribution of approximately $1.0 million was paid on February 13, 2012 to unitholders of record as of the close of business on February 6, 2012.
On April 26, 2012, the board of directors declared a quarterly cash distribution for the first quarter of 2012 of $0.475 per unit. The distribution of approximately $8.6 million is to be paid on May 14, 2012 to unitholders of record at the close of business on May 7, 2012.
The following agreements were negotiated among affiliated parties and, consequently, are not the result of arms length negotiations. The following is a description of those agreements that have been entered into with the affiliates of our general partner and with our general partner. We, our general partner and its affiliates have entered into the various documents and agreements, which are described below.
We are party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provides certain services to us, including management, administrative and operational services to us, which include marketing, geological and engineering services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. During the three months ended March 31, 2012, we reimbursed Mid-Con Energy Operating approximately $0.6 million for direct expenses.
Other Transactions with Related Persons
We, various third parties with an ownership interest in the same property and our affiliate, Mid-Con Energy Operating, are party to standard oil and gas joint operating agreements, pursuant to which we and those third parties pay Mid-Con Energy Operating overhead charges associated with operating our properties (commonly referred to as the Council of Petroleum Accountants Societies, or COPAS fees). These costs are included in lease operating expenses in our unaudited consolidated statements of operations.
No new accounting pronouncements issued or effective during the three months ended March 31, 2012 have had or are expected to have a material impact on our consolidated financial statements.
On April 23, 2012, the borrowing base for our current credit facility was increased from $75.0 million to $100.0 million and Wells Fargo Bank, N.A., was added as an additional lender. No other material terms of the agreement were amended.
On April 26, 2012, the board of directors declared a quarterly cash distribution for the first quarter of 2012 of $0.475 per unit. The distribution of $8.6 million is to be paid on May 14, 2012 to unitholders of record at the close of business on May 7, 2012.
Managements Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto, as well as our Annual Report.
We are a Delaware limited partnership formed in July 2011 to own, operate, acquire, exploit and develop producing oil and natural gas properties in North America, with a focus on the Mid-Continent region of the United States. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Our properties are located in the Mid-Continent region of the United States in three core areas: Southern Oklahoma, Northeastern Oklahoma and parts of Oklahoma and Colorado within the Hugoton Basin. Our properties primarily consist of mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low production decline rates.
In December 2011, we completed our initial public offering of 5,400,000 common units at an initial public offering price of $18.00 per unit, and on January 9, 2012, we closed the sale of an additional 810,000 common units pursuant to the exercise of the underwriters over-allotment option. Upon the closing of our initial public offering (and taking into account the underwriters exercise of their over-allotment option), we had 17,640,000 common units and 360,000 general partner units outstanding, representing a 98% limited partner interest in us, and a 2.0% general partner interest, respectively.
Our primary business objective is to manage our oil and natural gas properties for the purpose of generating stable cash flows, which will provide stability and, over time, growth of distributions to our unitholders. The amount of cash that we can distribute to our unitholders depends principally on the cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other factors:
While oil prices have steadily increased since the second quarter of 2009, the outlook and timing for a worldwide economic recovery remains uncertain for the foreseeable future. As a result, it is likely that commodity prices will continue to be volatile. Sustained periods of low prices for oil could materially and adversely affect our financial position, our results of operations, the quantities of oil reserves that we can economically produce and our access to capital.
Our hedging strategy seeks to reduce the impact to our cash flow from commodity price volatility. We intend to enter into commodity derivative contracts at times and on terms designed to maintain, over the long term, a portfolio covering our estimated oil production from proved reserves over a three-to-five year period at any given point in time. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes or the duration of our hedge contracts when circumstances suggest that it is prudent to do so.
Our business faces the challenge of natural production declines. As initial reservoir pressures are depleted, oil production from a given well or formation decreases. Although our waterflood operations tend to restore reservoir pressure and production, once a waterflood is fully effected, production, once again, begins to decline. Our future growth will depend on our ability to continue to add reserves in excess of our production. We plan to maintain our focus primarily on adding reserves through improving the economics of producing oil from our existing fields and, secondarily, through acquisitions of additional proved reserves. Our ability to add reserves through exploitation projects and acquisitions is dependent upon many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel, and successfully identify and close acquisitions.
We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flows from operations are impacted by our ability to manage our overall cost structure.
The table below summarizes certain of the results of operations for the periods indicated (in thousands, except operating and per unit amounts). The data for the periods reflect our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report.
Net income was approximately $1.7 million for the three months ended March 31, 2012 compared to approximately $2.0 million for the three months ended March 31, 2011, a decrease of $0.3 million. This decrease primarily reflects higher unrealized loss on derivatives, higher general and administrative expenses (including equity-based compensation expense), and higher production taxes partially offset by increased oil revenues.
Sales Revenues. Revenues from oil and natural gas sales for the three months ended March 31, 2012 were approximately $15.5 million as compared to approximately $7.2 million for the three months ended March 31, 2011. The increase in revenues was primarily due to an increase in daily oil production and higher sales prices during the first quarter of 2012.
Our production volumes for the three months ended March 31, 2012 were approximately 155 MBoe, or approximately 1,703 Boe per day. In comparison, our total production volumes for the three months ended March 31, 2011 were approximately 83 MBoe, or approximately 922 Boe per day on average. The increase in production volumes was primarily due to ongoing waterflood response and the drilling programs in our Southern Oklahoma waterflood units, in addition to the acquisitions of interests in various properties located in the Hugoton Basin area. Our average sales price per barrel for oil, excluding commodity derivative contracts, for the three months ended March 31, 2012 was $102.24, compared with $89.62 for the three months ended March 31, 2011.
Effects of Commodity Derivative Contracts. Due to changes in commodity prices, we recorded a net loss from our commodity hedging program for the three months ended March 31, 2012 of approximately $4.9 million, which was composed of a realized loss of approximately $0.1 million and an unrealized loss of approximately $4.8 million. For the three months ended March 31, 2011, we recorded a net loss from our commodity hedging program of approximately $1.2 million, which was composed of a realized loss of approximately $0.1 million and an unrealized loss of approximately $1.1 million.
Lease Operating Expenses. Our lease operating expenses were approximately $1.9 million for the three months ended March 31, 2012, or $12.56 per Boe, compared to approximately $1.6 million for the three months ended March 31, 2011, or approximately $19.78 per Boe. The increase in total lease operating expenses during the three months ended March 31, 2012 was primarily attributable to an increase in production resulting from our drilling programs and the increase in the number of producing wells. The decrease in lease operating expenses per Boe was due to the increased production for the three months ended March 31, 2012. Ad valorem taxes are also reflected in lease operating expenses. Ad valorem taxes are levied on our properties in Colorado and are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts, and a percentage of production equipment value.
Production Taxes. Our production taxes were approximately $0.7 million for the three months ended March 31, 2012, or approximately $4.33 per Boe for an effective tax rate of approximately 4.3%, compared to approximately $0.3 million for the three months ended March 31, 2011, or approximately $3.73 per Boe for an effective tax rate of approximately 4.3%. The increase in production taxes during the three months ended March 31, 2012 was primarily due to the increased production and the realized average oil sales price. Production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts. The State of Oklahoma, where most of our properties are located, currently imposes a production tax of 7.2% for oil and natural gas properties and an excise tax of 0.095%, a portion of our wells in Oklahoma continue to receive a reduced production rate due to the Enhanced Recovery Project Gross Production Tax Exemption.
Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses on producing properties for the three months ended March 31, 2012 were approximately $2.3 million, or approximately $14.92 per Boe produced, compared to approximately $1.4 million, or approximately $16.57 per Boe produced, for the three months ended March 31, 2011. The increase in depreciation, depletion and amortization expenses was primarily due to the increase in proved developed reserves estimated at March 31, 2012, in addition to the acquisition of waterflood units in our Hugoton Basin and Southern Oklahoma core areas. The decrease in the price per Boe produced was primarily due to the increase in proved developed reserves during the three months ended March 31, 2012.
General and Administrative Expenses. Our general and administrative expenses were approximately $3.6 million for the three months ended March 31, 2012, or approximately $23.42 per Boe produced compared to approximately $0.1 million for the three months ended March 31, 2011 or approximately $1.80 per Boe produced. The increase in general and administrative expenses for the three months ended March 31, 2012 is primarily due to higher compensation costs related to our non-cash equity-based compensation expense of $2.7 million, higher professional fees necessary to comply with public reporting requirements and incremental costs related to the hiring of additional staff. Also, during the first three months of 2011, revenues generated from Mid-Con Energy Operating, which was a subsidiary of our predecessor, were used to offset the general and administrative expenses.
Interest Expense. Our interest expense for the three months ended March 31, 2012 was $0.4 million, compared to $0.1 million for the three months ended March 31, 2011. The increase was primarily due to increased borrowings from our credit facility.
Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.
We believe a strong balance sheet is a necessary pre-requisite for creating sustainable growth in unitholder value. Our liquidity position as of March 31, 2012 consisted of approximately $5.6 million of available cash, and $33.0 million of available borrowings under our credit facility. We 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 March 31, 2012, our $250.0 million credit facility had borrowing capacity of $33.0 million ($75.0 million borrowing base less $42.0 million of outstanding borrowings under our credit facility). The borrowing base will be re-determined on or about April 30 and October 31 of each year, beginning with April 30, 2012. On April 23, 2012 the borrowing base of our credit facility was increased from $75.0 million to $100.0 million.
Operating Activities. Net cash provided by operating activities was approximately $14.1 million and $2.9 million for the three months ended March 31, 2012 and 2011, respectively. Our revenues increased significantly for the three months ended March 31, 2012 compared to 2011, primarily due to increased production, favorable commodity pricing, our successful exploitation of our proved reserves, our ability to reduce our per unit operating expenses and our successful acquisition activity. Cash provided by operating activities is impacted by the prices we received for oil and natural gas sales and levels of our production volumes. Our production volumes in the future will in large part be dependent upon the results of past waterflood development activities and results of future capital expenditures. Our future levels of capital expenditures may vary due to many factors, including development and drilling results, oil and natural gas prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.
Investing Activities. Net cash used in investing activities was approximately $4.6 million and approximately $6.3 million for the three months ended March 31, 2012, and 2011, respectively. The decrease in the amount of cash used in investing activities for the three months ended March 31, 2012 was primarily due to the decreased waterflood development activities in our Southern Oklahoma core area, including the in-field drilling in these units and acquisition of interest in oil properties. These capital expenditures which occurred during the last part of 2011 and the balance of which were paid during the first quarter of 2012, were part of the working capital prepaid by our predecessor.
Financing Activities. Net cash (used in) provided by financing activities was approximately ($4.0) million and approximately $4.1 million for the three months ended March 31, 2012 and 2011, respectively. During the first three months ended March 31, 2012, we paid borrowings outstanding under our credit facility by $3.0 million and had cash distributions of approximately $1.0 million. For the three months ended March 31, 2011, the cash provided by financing activities primarily related to $4.1 million from borrowings.
We currently expect for the remainder of 2012 spending for the development, growth and maintenance of our oil and natural gas properties to be approximately $12.8 million. We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisition of oil and natural gas properties in 2012 with the issuance of equity, debt financing or borrowings under our credit facility.
We are party to a $250.0 million senior secured revolving credit facility that expires in December 2016. Borrowings under the facility are secured by liens on not less than 80% of our assets and the assets of our subsidiary. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. At March 31, 2012, we had $42.0 million outstanding under the revolving credit facility.
The facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and payments. 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 facility agreement, together with accrued interest, could be declared immediately due and payable. As of March 31, 2012, we were in compliance with all debt covenants.
On April 23, 2012, the borrowing base of our credit facility was increased from $75.0 million to $100.0 million and Wells Fargo Bank, N.A. was added as an additional lender. No other material terms of the original credit facility were amended.
For additional information about our long-term debt, such as interest rates and covenants, please see Item 1. Condensed Consolidated Financial Statements (Unaudited) contained herein.
At March 31, 2012, our open commodity derivative contracts were in a net liability position with a fair value of approximately $2.2 million. All of our commodity derivative contracts are with major financial institutions. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments in the event of lower commodity prices and we could incur a loss. As of March 31, 2012, all of our counterparties have performed pursuant to their commodity derivative contracts.
All of our derivative contracts for 2012, 2013 and 2014 are either swaps with fixed settlements or collars. These instruments limit our exposure to declines in prices, but also limit the benefits if prices increase. We do not specifically designate commodity derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Realized gains or losses only arise from payments made or received on monthly settlements or if a commodity derivative contract is terminated prior to its expiration.
See Note 3 to the consolidated financial statements within this report for a discussion of our derivative contracts.
As of March 31, 2012, we had no offbalance sheet arrangements.
No new accounting pronouncements issued or effective during the three months ended March 31, 2012 have had or are expected to have a material impact on our consolidated financial statements.
We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business.
The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term market risk refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report and in our Annual Report.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil production. Realized pricing is primarily driven by the spot market prices applicable to the prevailing price for oil. Pricing for oil has been volatile and unpredictable for several
years, and this volatility is expected to continue in the future. The prices we receive for our oil production depend on many factors outside of our control, such as the strength of the global economy.
To reduce the impact of fluctuations in oil prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into commodity derivative contracts with respect to a significant portion of our projected oil production through various transactions that fix the future prices received. These hedging activities are intended to manage our exposure to oil price fluctuations. We do not enter into derivative contracts for speculative trading purposes.
Our oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, it is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers. We evaluate the credit standing of such counterparties by reviewing their credit ratings. The counterparties to our derivative contracts currently in place are lenders under our credit facility and have investment grade ratings. We expect to enter into future derivative contracts with these or other lenders under our credit facility whom we expect will also carry investment grade ratings.
The fair value of our oil and natural gas commodity contracts and swaps at March 31, 2012 was a net liability of $2.2 million. A 10% change in oil and natural gas prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts and swaps of approximately $8.7 million. Please see Item 1. Condensed Consolidated Financial Statements (Unaudited) contained herein for additional information.
Interest Rate Risk
At March 31, 2012, we had long-term debt outstanding of $42.0 million, with an effective interest rate of approximately 2.5%. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $0.1 million on an annual basis. The interest rate we pay under our credit facility ranges from LIBOR plus 1.75% to LIBOR plus 2.75% or the prime rate plus 0.75% to the prime rate plus 1.75%, depending on the amount borrowed. The prime rate will be the United States prime rate as announced from time-to-time by the Royal Bank of Canada. Please see Item 1. Condensed Consolidated Financial Statements (Unaudited) contained herein for additional information. On April 23, 2012, the borrowing base of our credit facility was increased from $75.0 million to $100.0 million.
Counterparty and Customer Credit Risk
We are subject to credit risk due to the concentration of our revenues attributable to two significant customers, Enterprise Crude Oil LLC (Enterprise) and Sunoco Logistics Partners, LP (Sunoco Logistics), for our 2012 production. The inability or failure of Enterprise, Sunoco Logistics or any other significant customer to meet its obligations to us, or its insolvency or liquidation may adversely affect our financial results. However, both Enterprise and Sunoco Logistics have a positive payment history and each have investment grade credit ratings. Accordingly, we believe that the credit quality of both Enterprise and Sunoco Logistics is high.
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 chief executive officer (principal executive officer) and chief financial officer (principal financial officer), the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on this evaluation, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.
Changes in Internal Controls 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 quarterly period ended March 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We have taken steps, including hiring additional accounting personnel and purchasing new accounting software, in an effort to enhance our internal control over financial reporting. We continue our efforts to ensure that the new accounting and control procedures that we have put in place are functioning properly.
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.
There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011.
The exhibits listed below are filed or furnished as part of this Quarterly Report:
+ Filed herewith
++ In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act. The financial information contained in the XBRL-related documents is unaudited or unreviewed.
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.