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CEP > SEC Filings for CEP > Form 10-K on 27-Mar-2014All Recent SEC Filings

Show all filings for CONSTELLATION ENERGY PARTNERS LLC

Form 10-K for CONSTELLATION ENERGY PARTNERS LLC


27-Mar-2014

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the "Item 6. Selected Financial Data" and the accompanying financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, forecasts, guidance, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, operating costs, lack of a sponsor, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in "Item 1A. Risk Factors" and "Forward-Looking Statements," all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are a limited liability company formed in 2005 to acquire oil and natural gas properties. Our proved reserves are located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas and in Texas and Louisiana. Our primary business objective is to create long-term value and to generate stable cash flows allowing us to invest in our business to grow our reserves and production. We plan to achieve our objective by executing our business strategy, which is to:

•organically grow our business by increasing reserves and production through what we believe to be low-risk development drilling that focuses on capital efficient production growth and oil opportunities on our existing properties in the Mid-Continent region and in Texas and Louisiana;

•reduce the volatility in our cash flows resulting from changes in oil and natural gas commodity prices and interest rates through efficient and effective hedging programs; and

•make accretive, right-sized acquisitions of oil and natural gas properties characterized by a high percentage of proved developed oil and natural gas reserves with long-lived, stable production and low-risk drilling opportunities.

We completed our initial public offering on November 20, 2006, and our Class B common units are currently listed on the NYSE MKT under the symbol "CEP."


Unless the context requires otherwise, any reference in this Annual Report on Form 10-K to "Constellation Energy Partners," "we," "our," "us," "CEP," or the "Company" means Constellation Energy Partners LLC and its subsidiaries. References in this Annual Report on Form 10-K to "PostRock" and "CEPM" are to PostRock Energy Corporation and its subsidiary Constellation Energy Partners Management, LLC, respectively. References in this Annual Report on Form 10-K to "Exelon" and "CEPH" are to Exelon Corporation and its subsidiary Constellation Energy Partners Holdings, LLC, respectively. References in this Annual Report on Form 10-K to "SOG" and "SEP I" are to Sanchez Oil & Gas Corporation and its subsidiary, Sanchez Energy Partners I, LP, respectively. References in this Annual Report on Form 10-K to "Constellation" are to Constellation Energy Group, Inc.

Some key highlights of our business activities through December 31, 2013 were:

•We sold our Robinson's Bend Field assets in the Black Warrior Basin in Alabama and used a portion of the proceeds from that sale to reduce our outstanding debt. As a result of this sale, amounts related to the Robinson's Bend Field assets have been reported as discontinued operations in 2013. All prior year information relating to the Robinson's Bend Field assets has been restated as discontinued operations, and all information reported or discussed in this Annual Report on Form 10-K reflects the treatment of the Robinson's Bend Field assets as discontinued operations.

•We amended our reserve-based credit facility to extend its maturity to May 2017 and expand our borrowing capacity.

•We acquired producing oil and natural gas assets in Texas and Louisiana from SEP I.

•We executed a capital plan that allowed us to expand our oil production from 2010 to 2013 by 262.3% and increased our proved oil reserves to 2.2 million barrels at December 31, 2013. Oil revenues accounted for 50.5% of our total unhedged revenue stream in 2013.

•We have reduced our outstanding debt by 77.0% from a high of $220.0 million in 2009 to $50.7 million.

In 2014, we intend to focus our efforts on developing oil opportunities on our existing properties in the Mid-Continent region and in Texas and Louisiana, while pursuing opportunities to acquire additional properties in our operating area or merger and acquisition opportunities that could lead to enhanced unitholder value. For additional information on our business plan for 2014, refer below to "Outlook."

Significant Operational Factors in 2013

• Realized Prices. Our average realized price for the twelve months ended December 31, 2013, including hedge settlements, was $7.49 per Mcfe and $5.56 per Mcfe excluding hedge settlements. After deducting the cost of sales associated with third party gathering, our average realized prices were $7.32 per Mcfe including hedge settlements and $5.39 per Mcfe excluding hedge settlements.

•Production. Our production for the twelve months ended December 31, 2013, was approximately 8.2 Bcfe, or an average of 22,433 Mcfe per day compared with approximately 8.2 Bcfe, or an average of 22,418 Mcfe per day for the twelve months ended December 31, 2012.

•Capital Expenditures and Drilling Results. For the twelve months ended December 31, 2013, we spent approximately $35.9 million in cash capital expenditures, consisting of $15.3 million in development expenditures focused on oil completions in the Cherokee Basin, $0.1 million to acquire certain additional natural gas wells in the Cherokee Basin, $20.1 million to acquire SEP I properties, and $0.4 million in development expenditures focused on SEP I acquired properties. We completed 64 net wells and 15 net recompletions during 2013 and had 6 net wells and recompletions in progress at December 31, 2013.

• Oil and Natural Gas Reserves. Our total year end 2013 proved reserves were
91.3 Bcfe, which is 47.7 Bcfe higher than our year end 2012 proved reserves of
43.6 Bcfe, due to the sale of our Black Warrior Basin assets, partially offset by higher SEC natural gas and oil prices and the purchase of the SEP I properties in Texas and Louisiana. Our 2013 estimates of proved reserves were prepared in accordance with the SEC rules for oil and natural gas reserve reporting that require our proved reserves to be calculated using an average of the NYMEX spot prices for the sales of oil and natural gas on the first calendar day of each month of the year, adjusted for basis differentials. We increased our proved oil reserves from 1.1 MBbl to 2.2 MBbl or by 100% by focusing our capital programs on drilling locations that have oil completions. Any of our locations that are scheduled to be drilled after five years are classified as probable or possible reserves if they are economic. Our reserves are 85% natural gas and are sensitive to lower SEC-required prices for natural gas and basis differentials in the Mid-Continent region. The 12-month average SEC-required price used to prepare our reserve report was $3.71 per Mcf. Although we utilize swaps and basis swaps to mitigate commodity price risk and basis differentials, these derivatives are not used when preparing our reserve report based on SEC rules. We do not use the SEC-required 12-month average price to make investment or drilling decisions. Instead, we use estimates of expected future observable market prices for oil and natural gas.


•Reduction of Outstanding Debt. Through December 31, 2013, we reduced our outstanding debt from a high of $220.0 million in 2009 to $50.7 million, or by 77.0%, which currently leaves us with $4.3 million of funds available for borrowing under our reserve-based credit facility which matures on May 30, 2017.

•Hedging Activities. All of our derivatives are accounted for as mark-to-market activities. For the twelve months ended December 31, 2013, the non-cash mark-to-market loss was approximately $17.3 million, compared to non-cash mark-to-market loss of $8.7 million for the same period in 2012.

We experience earnings volatility as a result of using the mark-to-market accounting method for our open derivative positions. This accounting treatment can cause extreme earnings volatility as the positions for future oil and natural gas production or interest rates are marked-to-market. These non-cash gains or losses are included in our current statement of operations until the derivatives are cash settled as the commodities are produced and sold or interest payments are made. Further detail of our open derivative positions and their accounting treatment is outlined below in "-Cash Flow From Operations-Open Commodity Hedge Positions" and "Critical Accounting Polices and Estimates-Hedging Activities."

•Operating Expense Reductions. We are currently implementing strategies to lower our operating expenses. For the year ended December 31, 2013, we have reduced our lease operating expenses by 2.8%, compared to the same period in 2012 and reduced our general and administrative expenses by 10% when not including litigation and accrued settlement charges in the fourth quarter of 2013.

Significant Market Factors

•PostRock as an "Interested Unitholder". In 2011, PostRock acquired certain of our Class A and Class B common units in two separate transactions which represented a 21.3% ownership interest in us as of December 31, 2013. Approval of the purchase of these units was neither required nor given by our board of managers or conflicts committee. We believe PostRock is now an "interested unitholder" under Section 203 of the Delaware General Corporation Law, which is applicable to us pursuant to our operating agreement. Section 203, as it applies to us, prohibits an interested unitholder, defined as a person who owns 15% or more of our outstanding common units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder without the approval of our board of managers and the vote of 66 2/3% of our outstanding Class B common units, excluding those held by the interested unitholder. Section 203 broadly defines "business combination" to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. In addition to limiting our ability to enter into transactions with PostRock or its affiliates, this provision of our operating agreement could have an anti-takeover effect with respect to transactions not approved in advance by our board of managers, including discouraging takeover attempts that might result in a premium over the market price for our common units. We believe the
Section 203 restrictions related to these unit purchases expire in December 2014.


Results of Operations

The following table sets forth the selected financial and operating data for the periods indicated (in thousands, except net production and average sales and costs):

                                              For the year ended         2013 vs. 2012 Variance
                                                 December 31,
                                             2013           2012           $              %
Revenues:
Natural gas sales at market price         $   20,999     $   15,746        5,253          33.4  %
Natural gas hedge settlements                 15,550         23,654       (8,104)        (34.3) %
Natural gas mark-to-market activities        (16,528)        (8,538)      (7,990)        (93.6) %
Natural gas total                             20,021         30,862      (10,841)        (35.1) %
Oil and liquids sales                         21,456         11,923        9,533          80.0  %
Oil hedge settlements                            245            753         (508)        (67.5) %
Oil mark-to-market activities                   (753)          (168)        (585)       (348.2) %
Oil and liquids total                         20,948         12,508        8,440          67.5  %
Miscellaneous income                           3,108          3,157          (49)         (1.6) %
Total revenues                                44,077         46,527       (2,450)         (5.3) %
Operating expenses:
Lease operating expenses                      18,858         19,411         (553)         (2.8) %
Cost of sales                                  1,455          1,299          156          12.0  %
Production taxes                               2,601          1,646          955          58.0  %
General and administrative                    22,214         15,747        6,467          41.1  %
Loss on sale of assets                             4              7           (3)        (42.9) %
Depreciation, depletion and amortization      18,972         11,732        7,240          61.7  %
Asset impairments                              2,357            109        2,248       2,062.4  %
Accretion expenses                               519            459           60          13.1  %
Total operating expenses                      66,980         50,410       16,570          32.9  %
Other expenses (income):
Interest expense                               6,798          6,891          (93)         (1.3) %
Interest expense - gain from                  (3,648)        (1,157)      (2,491)        215.3  %
mark-to-market activities
Interest income                                     -            (1)           1        (100.0) %
Other income                                    (196)          (154)         (42)         27.3  %
Total other expenses (income)                  2,954          5,579       (2,625)        (47.1) %
Total expenses                                69,934         55,989       13,945          24.9  %
Loss from discontinued operations             (2,686)       (77,081)      74,395         (96.5) %
Net loss                                  $  (28,543)    $  (86,543)      58,000         (67.0) %

Net production:
Natural gas production (MMcf)                  6,862          7,482         (620)         (8.3) %
Oil and liquids production (MBbl)                221            121          100          82.6  %
Total production (Mmcfe)                       8,188          8,205          (17)         (0.2) %
Average daily production (Mcfe/d)             22,433         22,418           15           0.1  %
Average sales prices:
Natural gas price per Mcf with hedge      $     5.78     $     5.69         0.09           1.6  %
settlement
Natural gas price per Mcf without hedge   $     3.51     $     2.53         0.98          38.7  %
settlements
Oil and liquids price per Bbl with hedge  $    98.18     $   105.22        (7.04)         (6.7) %
settlements
Oil and liquids price per Bbl without     $    97.07     $    98.97        (1.89)         (1.9) %
hedge settlements
Total price per Mcfe with hedge           $     7.49     $     6.73         0.76          11.3  %
settlements
Total price per Mcfe without hedge        $     5.56     $     3.76         1.80          47.9  %
settlements
Total price per BOE with hedge            $    44.96     $    40.38         4.58          11.3  %
settlements
Total price per BOE without hedge         $    33.39     $    22.53        10.86          48.2  %
settlements
Average unit costs per Mcfe:
Field operating expenses???               $     2.62     $     2.57         0.05           1.9  %
Lease operating expenses                  $     2.30     $     2.37        (0.07)         (3.0) %
Production taxes                          $     0.32     $     0.20         0.12          60.0  %
General and administrative expenses       $     2.71     $     1.92         0.79          41.4  %
General and administrative expenses       $     2.59     $     1.74         0.85          48.6  %
without unit-based compensation
Depreciation, depletion and amortization  $     2.32     $     1.43         0.89          62.2  %

(a)Field operating expenses include lease operating expenses (average production costs) and production taxes


Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Oil and natural gas sales. Unhedged natural gas sales increased $5.3 million, or 33.4%, to $21.0 million for the year ended December 31, 2013, compared to $15.7 million in 2012. Unhedged oil and liquid sales increased $9.5 million, or 80.0%, to $21.4 million for the year ended December 31, 2013, compared to $11.9 million for the same period in 2012. With hedges and mark-to-market activities, our total revenue decreased $2.4 million when compared to the same period in 2012. Of this decrease, $8.6 million was attributable to lower hedge settlements for our oil and natural gas commodity derivatives and $8.6 million was attributable to lower mark-to-market activities, partially offset by $14.8 million related to higher market prices for natural gas and oil. Production for the twelve months ended December 31, 2013 was 8.2 Bcfe, which was comparable to the same period in 2012. We hedged all of our actual consolidated production volumes sold through December 31, 2013, and approximately 81% of our actual production through December 31, 2012. In March 2013, we liquidated or repositioned certain of our hedges to ensure that our outstanding derivative positions in future periods are lower than our expected future natural gas production in those periods.

Cash hedge settlements received for our commodity derivatives were approximately $15.8 million for the year ended December 31, 2013. Cash hedge settlements received for our commodity derivatives were approximately $24.4 million for the year ended December 31, 2012. This difference is due to changes in hedge prices, hedged volumes and market prices for natural gas and oil during 2012 and 2013.

As discussed below, our non-cash mark-to-market activities decreased by $8.6 million for the year ended December 31, 2013, compared to the same period in 2012. Our realized prices before our hedging program decreased from 2012 to 2013 primarily due to net higher market prices for our natural gas production. This was offset by our hedging program and the mark-to-market gains and losses discussed below.

Hedging and mark-to-market activities. As of December 31, 2013, all of our hedges were accounted for as mark-to-market activities. For the year ended December 31, 2013, the non-cash mark-to-market loss was approximately $17.3 million as compared to a non-cash mark-to-market loss of approximately $8.7 million for the same period in 2012. The entire 2013 non-cash loss represented the impact of higher than expected future oil and natural gas prices on our derivative transactions that were being accounted for as mark-to-market activities.

Field operating expenses. Our field operating expenses generally consist of lease operating expenses, labor, vehicle, supervision, transportation, minor maintenance, tools and supplies expenses, as well as production and ad valorem taxes.

For the year ended December 31, 2013, lease operating expenses decreased $0.5 million, or 2.8%, to $18.9 million, compared to expenses of $19.4 million for the same period in 2012. This $0.5 million decrease in lease operating expenses is related to $0.7 million in lower elective costs such as well servicing and repairs and maintenance and $0.5 million in lower insurance, partially offset by higher labor costs of $0.7 million.

For the year ended December 31, 2013, per unit lease operating expenses were $2.30 per Mcfe compared to $2.37 per Mcfe for the same period in 2012.

For the year ended December 31, 2013, production taxes increased $1.0 million, or 58.0%, to $2.6 million, compared to production taxes of $1.6 million for the same period in 2012. This increase is primarily the result of higher market prices for natural gas and oil in 2013.

Cost of sales. For the year ended December 31, 2013, cost of sales increased by $0.2 million, or 12.0%, to $1.5 million, compared to $1.3 million for the same period in 2012.

General and administrative expenses. General and administrative expenses include the costs of our employees, related benefits, professional fees, general business and public company expenses, and any other administrative costs not directly associated with field operations.

General and administrative expenses increased $6.5 million, or 41.1%, to $22.2 million for the year ended December 31, 2013, compared to $15.7 million for the same period in 2012. Our general and administrative expenses were higher in 2013, compared to 2012 because of $6.2 million in higher audit, consulting, and legal services, and $1.0 million in severance costs, partially offset by $0.5 million in decreased labor and incentive compensation costs and $0.2 million in decreased unit-based compensation costs. The increased legal fees are the result of the PostRock litigation and the anticipated settlement of $5.9 million.

Our per unit general and administrative costs were $2.71 per Mcfe for the year ended December 31, 2013, compared to $1.92 per Mcfe for the same period in 2012. This increase is attributable to an increase in total spending of $6.5 million.


Depreciation, depletion and amortization expense and Asset impairments. Depreciation, depletion and amortization expenses include the depreciation, depletion and amortization of acquisition and equipment costs. Asset impairment expense is incurred when the fair value of our assets is less than their historical net book value. Depletion is calculated using units-of-production. Assuming everything else remains unchanged, as natural gas production changes, depletion would change in the same direction.

Our depreciation, depletion and amortization expense for the year ended December 31, 2013 was $18.9 million, or $2.32 per Mcfe, compared to $11.7 million, or $1.43 per Mcfe, for the same period in 2012. This increase of $7.2 million, or 61.7%, reflects the decrease in our reserve base at December 31, 2012, primarily due to the impact of a lower SEC-required natural gas price used to calculate our reserves which resulted in negative reserve revisions, and increased expenditures incurred for our drilling programs in 2012. These revisions were partially offset by increased oil reserves as a result of our successful drilling programs We calculate depletion using units-of-production under the successful efforts method of accounting. Our other assets are depreciated using the straight line basis. We will use our 2013 year-end reserve report to record our depletion in the first three quarters of 2014 and our 2014 year-end reserve report to record our depletion in the fourth quarter of 2014.

Our asset impairment charges for the year ended December 31, 2013 were $2.3 million, compared to $0.1 million for the same period in 2012. Our impairment charges in 2013 were approximately $2.1 million to impair the value of our oil and natural gas fields in Texas and Louisiana and $0.2 million to impair certain of our wells in the Woodford Shale, both due to decreases in commodity pricing. Our impairment charges in 2012 were approximately $0.1 million to impair certain of our wells in the Woodford Shale. The impairment was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report.

Interest expense. Net interest expense for the year ended December 31, 2013 decreased $2.6 million, or 45.1%, to approximately $3.1 million, compared to approximately $5.7 million in interest expense for the same period in 2012. This decrease was primarily due to $1.5 million in higher interest rate swap settlements, offset by $2.5 million lower non-cash mark-to-market losses on our interest rate swaps that are accounted for as mark-to-market activities and lower market interest rates resulting in lower interest expense of $1.6 million during 2013 as compared to the same period in 2012. At December 31, 2013, we had an outstanding balance under our reserve-based credit facility of $50.7 million, compared to $84.0 million at December 31, 2012.

Discontinued Operations. Loss from discontinued operations for the year ended December 31, 2013 decreased $74.4 million, or 96.5%, to a loss of $2.7 million, compared to a loss of $77.1 million in discontinued operations for the same period in 2012. Our discontinued operations represent the net loss associated with the sale of our Robinson's Bend Field assets in the Black Warrior Basin of Alabama, in a transaction that closed on February 28, 2013, with an effective date of December 1, 2012. The loss in 2013 reflects a $3.1 million loss on the sale of the properties, only two months of income and lower depreciation expenses.

Liquidity and Capital Resources

During 2013, we utilized our cash flow from the sale of our Robinson's Bend Field assets, as well as our cash flow from operations, as our primary sources of capital. Our primary use of capital during this time was for the reduction of outstanding debt, the acquisition of properties and the development of existing oil opportunities within our existing asset base in the Mid-Continent and Gulf Coast regions.

The primary focus of our business plan in 2013 was to use our excess operating cash flows to reduce our outstanding debt level while continuing a limited capital program focused on oil drilling and recompletions. Since we shifted our strategic focus to debt reduction, we have successfully reduced our outstanding debt balance from a high of $220.0 million in 2009 to $50.7 million as of December 31, 2013. This reduction in debt was achieved through a combination of the sale of our natural gas properties in the Black Warrior Basin of Alabama in 2013, the one-time restructuring of our NYMEX fixed-for-floating price swaps in 2011, the suspension of our cash distribution since 2009, the reduction of our capital expenditures since 2009, significant reductions in our operating expenses and the dedication of a significant portion of our operating cash flows to reducing debt.

Based upon our current business plan for 2014, we anticipate that we will continue to generate sufficient operating cash flows to meet our working capital needs and fund a planned capital expenditure program between $20.0 million and $22.0 million. We also anticipate that we will have funds available to pay the probable settlement related to the PostRock litigation of approximately $5.9 million. We will be monitoring the capital resources available to us to meet our future financial obligations and our planned 2014 capital expenditures. Our current expectation is that we will continue managing our business to operate within the cash flows that are generated. Given our focus on debt reduction, our quarterly distributions to our unitholders remained suspended through the fourth quarter of 2013. We were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business and the payment of fees and expenses) from which to pay distributions.

Our future success in growing reserves and production will be highly dependent . . .

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