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EVEP > SEC Filings for EVEP > Form 10-Q on 12-Nov-2013All Recent SEC Filings

Show all filings for EV ENERGY PARTNERS, LP

Form 10-Q for EV ENERGY PARTNERS, LP


12-Nov-2013

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto, as well as our Annual Report on Form 10-K for the year ended December 31, 2012.

OVERVIEW

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. Our general partner is EV Energy GP, a Delaware limited partnership, and the general partner of our general partner is EV Management, a Delaware limited liability company.

As of December 31, 2012, our properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the San Juan Basin, Central and East Texas (which includes the Austin Chalk area), the Permian Basin, the Monroe Field in Louisiana, and Michigan. As of December 31, 2012, we had estimated net proved reserves of 13.5 MMBbls of oil, 609.5 Bcf of natural gas and 35.7 MMBbls of natural gas liquids, or 904.7 Bcfe, and a standardized measure of $866.9 million.

CURRENT DEVELOPMENTS

In the nine months ended September 30, 2013, we invested $172.0 million in our unconsolidated affiliates, which included $33.3 million to increase our ownership in UEO from 8% to 21%.

In August 2013, we, along with certain institutional partnerships managed by EnerVest, signed an agreement to divest certain Utica shale acreage in Ohio for $56 million, net to us, subject to customary purchase price adjustments. In October 2013, we closed on the sale of $41.2 million of these acres, and we expect additional closings on the remaining acreage prior to year end.

In October 2013, we closed a public offering of 5.75 million common units at an offering price of $36.86 per common unit. We received proceeds of $208.7 million, including a contribution of $4.2 million by our general partner to maintain its 2% interest in us, and we expect to incur offering expenses of approximately $0.3 million. We used the proceeds to repay indebtedness outstanding under our credit facility. As of October 31, 2013, we had $442.0 million outstanding under our credit facility.

In October 2013, the borrowing base under the facility was increased to $730.0 million.

In November 2013, we, along with certain institutional partnerships managed by EnerVest, acquired natural gas properties in the Barnett Shale. We acquired a 31% proportional interest in these assets for $58.6 million, subject to customary purchase price adjustments.

BUSINESS ENVIRONMENT

Our primary business objective is to provide stability and growth in cash distributions per unit over time. The amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things:

the prices at which we will sell our oil, natural gas liquids and natural gas production;

our ability to hedge commodity prices;

the amount of oil, natural gas liquids and natural gas we produce; and

the level of our operating and administrative costs.

Oil, natural gas and natural gas liquids prices have been and are expected to continue to be volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas and natural gas liquids include the discovery of substantial accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves, North American weather conditions, industrial and consumer demand for natural gas and natural gas liquids, storage levels of natural gas and natural gas liquids and the availability and accessibility of natural gas deposits in North America.

In order to mitigate the impact of changes in prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of price volatility on our cash flows. By removing a significant portion of this price volatility on our future production through December 2015, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. If commodity prices are depressed for an extended period of time, it could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

The primary factors affecting our production levels are capital availability, our ability to make accretive acquisitions, the success of our drilling program and our inventory of drilling prospects. In addition, as initial reservoir pressures are depleted, production from our wells decreases. We attempt to overcome this natural decline through a combination of drilling and acquisitions. Our future growth will depend on our ability to continue to add reserves through drilling and acquisitions in excess of production. We will maintain our focus on the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact our production, which may have an adverse effect on our revenues and, as a result, cash available for distribution.

We focus our efforts on increasing our reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flows from operations are dependent upon our ability to manage our overall cost structure.

Utica Shale

Primarily through acquisitions completed in 2009 and 2010, we hold over 170,000 net working interest acres in Pennsylvania and Ohio and an approximate 2% average overriding royalty interest in 880,000 gross acres in Ohio which we believe may be prospective for the Utica Shale. In addition, partnerships managed by EnerVest own acreage which may be prospective for the Utica Shale. At September 30, 2013, our estimated net proved reserves in the Utica Shale were not material to us. Exploration and development activities targeting the Utica Shale are in the early stages, and it is possible that our estimates of the acreage in Ohio that we believe is prospective for the Utica Shale may change, perhaps materially, as additional exploration and development activities are conducted in the area. We do not expect to fully develop our Utica Shale properties for our account.

In mid-2012, we initiated the process for the monetization of a majority of our working interest acres related to the Utica Shale, and in August 2013, we, along with certain institutional partnerships managed by EnerVest, signed an agreement to divest certain Utica shale acreage in Ohio for $56 million, net to us, subject to customary purchase price adjustments. In October 2013, we closed on the sale of $41.2 million of these acres, and we expect additional closings on the remaining acreage prior to year end. Additional monetizations could take many forms, and we cannot at this time predict the type of transactions we may enter into or the type or amount of consideration we may receive. We may not be successful in our additional efforts to monetize the Utica Shale properties, it may take longer to complete the divestiture process than we expect, or we may decide to delay the monetization of all or a portion of the Utica Shale properties.

RESULTS OF OPERATIONS



                                             Three Months Ended          Nine Months Ended
                                                September 30,              September 30,
                                              2013          2012         2013          2012
Production data:
Oil (MBbls)                                       279          266           787          832
Natural gas liquids (MBbls)                       538          440         1,567        1,266
Natural gas (MMcf)                             10,555       10,772        31,879       31,757
Net production (MMcfe)                         15,453       15,008        46,000       44,349
Average sales price per unit:
Oil (Bbl)                                  $   102.15     $  89.83     $   96.26     $  93.64
Natural gas liquids (Bbl)                       30.72        32.07         29.98        37.63
Natural gas (Mcf)                                3.35         2.76          3.47         2.57
Mcfe                                             5.20         4.51          5.07         4.68
Average unit cost per Mcfe:
Production costs:
Lease operating expenses                   $     1.69     $   1.65     $    1.71     $   1.76
Production taxes                                 0.19         0.17          0.19         0.19
Total                                            1.88         1.82          1.90         1.95
Depreciation, depletion and amortization         1.81         1.88          1.88         1.83
General and administrative expenses              0.58         0.69          0.67         0.73

Three Months Ended September 30, 2013 Compared with the Three Months Ended September 30, 2012

Net loss for the three months ended September 30, 2013 was $(12.3) million compared with $(50.0) million for the three months ended September 30, 2012. This change reflects a $12.7 million increase in total revenues and a $49.3 million noncash reduction in the fair value of our derivatives partially offset by a $25.0 million reduction in realized gains on our derivatives.

Oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2013 totaled $80.3 million, an increase of $12.6 million compared with the three months ended September 30, 2012. This was the result of increases of $9.6 million related to higher prices for oil and natural gas and $4.3 million related to increased oil and natural gas liquids production offset by decreases of $0.6 million related to lower prices for natural gas liquids and $0.7 million related to decreased natural gas production.

Lease operating expenses for the three months ended September 30, 2013 increased $1.4 million compared with the three months ended September 30, 2012 primarily due to costs associated with the increased oil and natural gas liquids production. Lease operating expenses per Mcfe were $1.69 in the three months ended September 30, 2013 compared with $1.65 in the three months ended September 30, 2012.

Dry hole and exploration costs for the three months ended September 30, 2013 decreased $0.7 million compared with the three months ended September 30, 2012 primarily as a result of lower seismic costs at certain of our oil and natural gas properties in the Appalachian Basin.

Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for the three months ended September 30, 2013 increased $0.3 million compared with the three months ended September 30, 2012 primarily due to increased oil, natural gas and natural gas liquids revenues. Production taxes for the three months ended September 30, 2013 were $0.19 per Mcfe compared with $0.17 per Mcfe for the three months ended September 30, 2012.

Depreciation, depletion and amortization ("DD&A") for the three months ended September 30, 2013 decreased $0.2 million compared with the three months ended September 30, 2012 due to $1.0 million from a lower DD&A rate offset by $0.8 million from increased production. The lower average DD&A rate per unit reflects the impact prices had on our reserves estimates and increased reserves from our Barnett Shale drilling program. DD&A for the three months ended September 30, 2013 was $1.81 per Mcfe compared with $1.88 per Mcfe for the three months ended September 30, 2012.

General and administrative expenses for the three months ended September 30, 2013 totaled $8.9 million, a decrease of $1.4 million compared with the three months ended September 30, 2012. This decrease is primarily the result of $0.8 million of lower fees paid to EnerVest under the omnibus agreement and $0.5 million of decreased equity compensation costs. General and administrative expenses were $0.58 per Mcfe in the three months ended September 30, 2013 compared with $0.69 per Mcfe in the three months ended September 30, 2012.

In the three months ended September 30, 2013, we incurred leasehold impairment charges of $0.1 million compared with $0.8 million of leasehold impairment charges in the three months ended September 30, 2012.

Realized gains on derivatives, net consisted of the following for the three months ended September 30:

                                                               2013           2012

Cash settlements                                            $    5,361     $   31,248
Noncash realized loss related to acquired derivatives                -           (690 )
Noncash realized loss related to terminated interest rate
swaps                                                             (483 )         (723 )
Realized gains on derivatives, net                          $    4,878     $   29,835

The $25.8 million decrease in cash settlements is due to the impact of derivative contracts with more favorable terms that expired as of December 31, 2012 and, to a lesser extent, higher oil and natural gas prices.

Unrealized losses on derivatives, net consisted of the following for the three months ended September 30:

                                                               2013           2012

Change in the fair value of open derivatives                $  (17,008 )   $  (67,283 )
Change in value of acquired derivatives from the
beginning of the period                                              -            690
Change in value of terminated interest rate swaps                  483            723
Unrealized losses on derivatives, net                       $  (16,525 )   $  (65,870 )

Interest expense for the three months ended September 30, 2013 increased $0.1 million compared with the three months ended September 30, 2012 due to an increase of $3.9 million from a higher weighted average long-term debt balance offset by an increase of $1.8 million in capitalized interest and a decrease of $2.0 million from a lower weighted average interest rate.

Nine Months Ended September 30, 2013 Compared with the Nine Months Ended September 30, 2012

Net loss for the nine months ended September 30, 2013 was $(26.0) million compared with $(6.5) million for the nine months ended September 30, 2012. This change reflects (i) a $68.5 million reduction in realized gains on our derivatives and (ii) a $5.3 million increase in DD&A expense, partially offset by (iii) a $26.7 million increase in total revenues, (iv) a $14.2 million favorable noncash change in the fair value of our derivatives, and (v) a $9.6 million decrease in impairments of our oil and natural gas properties.

Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2013 totaled $233.3 million, an increase of $26.0 million compared with the nine months ended September 30, 2012. This was the result of increases of $30.6 million related to higher prices for oil and natural gas and $9.4 million related to increased natural gas and natural gas liquids production offset by decreases of $9.6 million related to lower prices for natural gas liquids and $4.4 million related to decreased oil production.

Lease operating expenses for the nine months ended September 30, 2013 increased $0.2 million compared with the nine months ended September 30, 2012 as the result of $1.7 million ($0.04 per Mcfe) of costs in the nine months ended September 30, 2012 associated with the sales of oil in tanks acquired in certain of our 2011 acquisitions, partially offset by costs associated with the increased natural gas and natural gas liquids production. Lease operating expenses per Mcfe were $1.71 in the nine months ended September 30, 2013 compared with $1.76 in the nine months ended September 30, 2012.

Dry hole and exploration costs for the nine months ended September 30, 2013 decreased $3.2 million compared with the nine months ended September 30, 2012 primarily as a result of decreased seismic costs at certain of our oil and natural gas properties in the Appalachian Basin.

DD&A for the nine months ended September 30, 2013 increased $5.3 million compared with the nine months ended September 30, 2012 due to $2.2 million from a higher DD&A rate and $3.1 million from increased production. The higher DD&A rate per unit reflects the impact that changes in prices had on our reserves estimates. DD&A for the nine months ended September 30, 2013 was $1.88 per Mcfe compared with $1.83 per Mcfe for the nine months ended September 30, 2012.

General and administrative expenses for the nine months ended September 30, 2013 totaled $30.7 million, a decrease of $1.9 million compared with the nine months ended September 30, 2012. This decrease is primarily the result of $2.3 million of lower fees paid to EnerVest under the omnibus agreement and $0.8 million of decreased due diligence costs partially offset by $0.9 million of higher compensation costs primarily related to our equity-based compensation plans. General and administrative expenses were $0.67 per Mcfe in the nine months ended September 30, 2013 compared with $0.73 per Mcfe in the nine months ended September 30, 2012.

In the nine months ended September 30, 2013, we incurred leasehold impairment charges of $8.1 million. In the nine months ended September 30, 2012, we incurred $1.1 million of leasehold impairment charges, $0.5 million of additional impairment charges to write down assets held for sale to their fair value and a $16.2 million impairment charge to write down oil and natural gas properties to their fair value asdetermined based on the expected present value of the future net cash flows from proved reserves. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

Realized gains on derivatives, net consisted of the following for the nine months ended September 30:

                                                               2013           2012

Cash settlements                                            $   21,749     $   91,345
Noncash realized loss related to acquired derivatives                -         (1,994 )
Noncash realized loss related to terminated interest rate
swaps                                                           (1,651 )         (723 )
Realized gains on derivatives, net                          $   20,098     $   88,628

The $69.6 million decrease in cash settlements is due to the impact of derivative contracts with more favorable terms that expired as of December 31, 2012 and, to a lesser extent, higher oil and natural gas prices.

Unrealized losses on derivatives, net consisted of the following for the nine months ended September 30:

                                                               2013           2012

Change in the fair value of open derivatives                $  (26,163 )   $  (41,389 )
Change in value of acquired derivatives from the
beginning of the period                                              -          1,994
Change in value of terminated interest rate swaps                1,651            723
Unrealized losses on derivatives, net                       $  (24,512 )   $  (38,672 )

Interest expense for the nine months ended September 30, 2013 increased $0.8 million compared with the nine months ended September 30, 2012 due to an increase of $8.8 million from a higher weighted average long-term debt balance offset by a decrease of $3.0 million due to a lower weighted average effective interest rate and an increase in capitalized interest in the nine months ended September 30, 2013 of $5.0 million.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our primary sources of liquidity and capital have been issuances of equity and debt securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, distributions to our unitholders and general partner and working capital needs. For 2013, we believe that cash on hand, proceeds from sales of assets, proceeds from our October 2013 public equity offering, net cash flows generated from operations and borrowings under our credit facility will be adequate to fund our capital budget, pay distributions to our unitholders and general partner and satisfy our short-term liquidity needs. We may also utilize borrowings under our credit facility and various financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund our acquisitions and long-term liquidity needs. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

Long-term Debt

As of September 30, 2013, we have a $1.0 billion credit facility that expires in April 2016. Borrowings under the facility may not exceed a "borrowing base" determined by the lenders based on our oil and natural gas reserves. As of September 30, 2013, the borrowing base was $710.0 million, and we had $585.0 million outstanding. In October 2013, the borrowing base was increased to $730.0 million.

As of September 30, 2013, we have $500.0 million in aggregate principal amount outstanding of 8.0% senior notes due 2019, and the aggregate carrying amount of the senior notes due 2019 was $499.3 million.

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.

Cash and Short-term Investments

At September 30, 2013, we had $10.6 million of cash and short-term investments, which included $7.3 million of short-term investments. With regard to our short-term investments, we invest in money market accounts with a major financial institution.

Counterparty Exposure

All of our derivative contracts are with major financial institutions who are also lenders under our credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of September 30, 2013, all of our counterparties have performed pursuant to their derivative contracts.

Cash Flows



Cash flows provided by (used in) type of activity were as follows:



                           Nine Months Ended
                             September 30,
                          2013           2012
Operating activities   $  119,235     $  175,033
Investing activities     (239,771 )     (228,627 )
Financing activities      123,688         34,246

Operating Activities

Cash flows from operating activities provided $119.2 million and $175.0 million in the nine months ended September 30, 2013 and 2012, respectively. The significant factor in the decrease was $69.6 million of decreased cash settlements from our derivatives.

Investing Activities

During the nine months ended September 30, 2013, we spent $75.8 million for additions to our oil and natural gas properties and increased our investment in unconsolidated affiliates by $172.0 million. In addition, we received $8.0 million in final purchase price settlements related to our August 2012 acquisition of additional working interests in acreage in Ohio.

During the nine months ended September 30, 2012, we spent $118.9 million for acquisitions of oil and natural gas properties and $100.4 million for additions to our oil and natural gas properties. We also increased our investment in unconsolidated affiliates by $19.0 million. In addition, we received $5.5 million from the sale of oil and natural gas properties and $4.2 million from the settlements of acquired derivatives.

Financing Activities

During the nine months ended September 30, 2013, we received $225.0 million from borrowings under our credit facility and paid distributions of $101.6 million to holders of our common units and our general partner.

During the nine months ended September 30, 2012, we received proceeds of $262.5 million, after payment of offering costs of $0.3 million, from our public equity offering in February 2012 and $201.9 million, after payment of offering costs of $4.1 million, from our debt offering in March 2012. We used the proceeds to repay $460.0 million of indebtedness outstanding under our credit facility. We also received $120.0 million from borrowings under our credit facility and contributions of $5.7 million from our general partner in order to maintain its 2% interest in us. In addition, we paid distributions of $95.8 million to holders of our common units, Class B units and our general partner.

FORWARD-LOOKING STATEMENTS

This 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 Exchange Act (each a "forward-looking statement"). These forward-looking statements relate to, among other things, the following:

our future financial and operating performance and results;

our business strategy and plans, including plans for the sale of acreage in the Utica Shale;

our estimated net proved reserves, PV-10 value and standardized measure;

market prices;

our future derivative activities; and

our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

The words "anticipate," "believe," "ensure," "expect," "if," "intend," "estimate," "project," "forecasts," "predict," "outlook," "aim," "will," "could," "should," "would," "may," "likely" and similar expressions, and the negative thereof, are intended to identify forward-looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10-Q including, but not limited to:

fluctuations in prices of oil, natural gas and natural gas liquids;

significant disruptions in the financial markets;

future capital requirements and availability of financing;

uncertainty inherent in estimating our reserves;

risks associated with drilling and operating wells;

discovery, acquisition, development and replacement of reserves;

cash flows and liquidity;

timing and amount of future production of oil, natural gas and natural gas liquids;

availability of drilling and production equipment;

marketing of oil, natural gas and natural gas liquids;

. . .

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