EV Energy Partners Announces Fourth Quarter and Full Year 2015 Results, Year-end Proved Reserves and 2016 Guidance

Feb 29, 2016, 06:37 ET from EV Energy Partners, L.P.

HOUSTON, Feb. 29, 2016 /PRNewswire/ -- EV Energy Partners, L.P. (NASDAQ: EVEP) today announced results for the fourth quarter and full year 2015 and the filing of its Form 10-K with the Securities and Exchange Commission.  In addition, EVEP announced its 2015 year-end proved reserves and 2016 guidance.

Fourth Quarter 2015 Results

Adjusted EBITDAX for the fourth quarter of 2015 was $52.7 million, a 5 percent decrease from the fourth quarter of 2014 and a 20 percent increase over the third quarter of 2015.  Distributable Cash Flow for the fourth quarter of 2015 was $26.1 million, a 4 percent increase over the fourth quarter of 2014 and a 30 percent increase over the third quarter of 2015.  The decrease in Adjusted EBITDAX from the fourth quarter of 2014 was primarily attributable to significantly lower realized commodity prices and the sale of midstream interests in the second quarter of 2015 partially offset by increased realized hedge gains on commodity derivatives and the addition of producing properties acquired on October 1, 2015.  The increase in Adjusted EBITDAX over the third quarter 2015 and the increases in distributable cash flow were primarily due to the addition of producing properties acquired on October 1, 2015.  Adjusted EBITDAX and Distributable Cash Flow are Non-GAAP financial measures and are described in the attached table under "Non-GAAP Measures."

Production for the fourth quarter of 2015 was 13.3 Bcf of natural gas, 351 Mbbls of oil and 655 Mbbls of natural gas liquids, or 209.8 million cubic feet equivalent per day (Mmcfe/day). This represents a 23 percent increase over fourth quarter 2014 production of 170.9 Mmcfe/d and a 36 percent increase over third quarter 2015 production of 153.8 Mmcfe/day.  The increase was primarily due to acquisitions completed on October 1, 2015.

EVEP reported a net loss of $71.3 million, or $(1.43) per basic and diluted weighted average limited partner unit outstanding, for the fourth quarter of 2015. Included in net loss were the following items:

  • $14.4 million of impairment charges primarily related to the write-down of certain oil and natural gas properties due to the effects of commodity prices on expected future net cash flows,
  • $65.9 million of impairment of goodwill related to properties acquired on October 1,
  • $24.0 million of gain on early extinguishment of debt related to repurchases of Senior Notes at a discount to par,
  • $18.2 million of non-cash losses on commodity and interest rate derivatives,
  • $2.4 million of non-cash costs contained in general and administrative expenses,
  • $2.0 million of dry hole and exploration costs,
  • $1.2 of loss on settlement of contract, and
  • $0.5 million of cash due diligence and other transaction costs contained in general and administrative expenses for properties acquired on October 1.

For the third quarter of 2015, EVEP reported a net loss of $9.8 million, or $(0.20) per basic and diluted weighted average limited partner unit outstanding.  For the fourth quarter of 2014, EVEP reported net income of $102.4 million, or $2.03 per basic and diluted weighted average limited partner unit outstanding.

Full Year 2015 Results

Adjusted EBITDAX and Distributable Cash Flow for 2015 of $203.9 million and $98.5 million decreased 10 percent and 12 percent, respectively, versus 2014.  The decreases in Adjusted EBITDAX and Distributable Cash Flow as compared to 2014 are primarily due to significantly lower realized commodity prices and the sale of our Utica midstream interests in the second quarter of 2015 partially offset by significantly higher realized hedge gains on commodity derivatives, decreased operating costs and expenses and the addition of producing properties acquired on October 1, 2015. 

Production for 2015 was 43.6 Bcf of natural gas, 1.0 Mbbls of oil and 2.3 Mbbls of natural gas liquids, or 174.8 Mmcfe/day, which is essentially flat compared to 2014 production of 174.1 Mmcfe/day.

For 2015, EVEP reported net income of $21.3 million, or $0.41 per basic and diluted weighted average limited partner unit outstanding.  Included in net income were the following items:

  • $255.5 million in income from discontinued operations, which includes $246.7 million of gain related to the sale of our interest in Utica East Ohio (UEO);
  • $136.7 million of impairment charges related to the write-down of certain oil and natural gas properties primarily due to the effects of commodity prices on expected future net cash flows and due to a change in the development plans for acreage in the Utica Shale,
  • $65.9 million of impairment of goodwill related to properties acquired on October 1,
  • $24.0 million of gain on early extinguishment of debt related to repurchases of Senior Notes at a discount to par,
  • $65.1 million of non-cash gains on commodity and interest rate derivatives,
  • $12.0 million of non-cash costs contained in general and administrative expenses,
  • $3.7 million of dry hole and exploration costs,
  • $1.2 of loss on settlement of contract,
  • $1.0 million of cash due diligence and other transaction costs contained in general and administrative expenses for properties acquired on October 1, and
  • $0.6 million gain on the sales of oil and natural gas properties.

For 2014, EVEP reported net income of $129.7 million, or $2.58 per basic and diluted weighted average limited partner unit outstanding. 

"We are pleased with our results for the fourth quarter, which were in-line with the midpoint of our previously issued guidance.  With this difficult and prolonged downturn, we have significantly reduced our capital budget for 2016 and are continuing to focus on further reducing our operating costs and maintaining financial flexibility and liquidity under our credit facility.  We currently have over $375 million of liquidity and, based on our guidance and current commodity prices, expect to generate free cash flow after interest expense and capital expenditures in 2016," said Michael Mercer, President and CEO.

Year-end 2015 Estimated Net Proved Reserves

EVEP's year-end 2015 estimated net proved reserves were 1,096.7 Bcfe.  Approximately 68 percent were natural gas, 20 percent were natural gas liquids and 12 percent were crude oil.  In addition, 83% percent were categorized as proved developed.  Year-end 2015 estimated net proved reserves increased by 96.3 Bcfe from year-end 2014 estimated net proved reserves.  The year-end 2015 reserve volumes include an increase of 330.5 Bcfe from acquisitions closed in the fourth quarter of 2015 and a reduction of 268.5 Bcfe primarily due to a significantly lower SEC pricing environment compared to year-end 2014.  The prices used in determining estimated net proved reserves at December 31, 2015 were $50.28 per Bbl of oil and $2.59 per Mmbtu of natural gas as compared to $94.99 per Bbl of oil and $4.35 per Mmbtu of natural gas at December 31, 2014.

At December 31, 2015, the present value of future net pre-tax cash flows discounted at 10 percent ("PV 10") was $539.9 million and the standardized measure (a non-GAAP measure) of estimated net proved reserves was $536.4 million.  Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (the "SEC"), without giving effect to non–property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.  Our standardized measure includes approximately $3.5 million of present value of future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes.  We have included PV 10 because we believe it is a measure frequently utilized by investors.

 

Estimated Net Proved Reserves

Crude Oil (MMBbls)

Natural Gas (Bcf)

NGL's (MMBbls)

Natural Gas Equivalents (Bcfe)

PV 10 ($mm)

Barnett Shale

0.5

356.5

22.9

497.0

$193.6

Appalachia Basin

15.0

106.1

0.6

199.5

143.3

San Juan Basin

1.0

99.7

6.2

143.1

49.4

Michigan

-

84.1

0.6

87.9

38.7

Central Texas

3.5

28.0

3.4

69.1

68.6

Mid-Continent area

1.6

27.6

0.6

40.8

30.9

Monroe Field

-

36.1

-

36.1

0.9

Permian Basin

0.4

8.9

2.0

23.2

14.5

22.0

747.0

36.3

1,096.7

$539.9

 

2015 capital spending of $67.9 million added SEC proved reserves of 100.6 Bcfe, resulting in a cost of $0.67 per Mcfe and reserve replacement of 158 percent.

 

2016 Guidance

($ in millions)

Full Year 2016

Net Production

Natural Gas (Mmcf)

47,670

-

52,685

Crude Oil (Mbbls)

1,220

-

1,345

Natural Gas Liquids (Mbbls)

2,230

-

2,465

Total Mmcfe

68,370

-

75,545

Average Daily Production (Mmcfe/d)

187

-

206

Net Transportation Margin(a)

$0.5

-

$1.0

Average Price Differential vs NYMEX

Natural Gas ($/Mcf)

($0.46)

-

($0.34)

Crude Oil ($/Bbl)

($4.50)

-

($3.00)

NGL (% of NYMEX Crude Oil)

30%

34%

Expenses

Operating Expenses:

LOE and other

$107.9

-

$119.3

Production Taxes (as % of revenue)

4.1%

-

5.1%

General and administrative expense(b)

$24.0

-

$28.0

E&P Capital Expenditures(c)

$10.0

-

$18.0

(a) 

Represents estimated transportation and marketing-related revenues less cost of purchased natural gas.

(b) 

Excludes non-cash general and administrative expense, of which non-cash unit based compensation is a part. Also excludes any amounts for future acquisition related due diligence and transaction costs.

(c) 

Represents estimates for drilling and related capital expenditures. Does not include any amounts for acquisitions of oil and gas properties.

 

Annual Report on Form 10-K and Unitholders' Schedule K-1

EVEP's financial statements and related footnotes are available on our 2015 Form 10-K, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP website at http://www.evenergypartners.com.

Also available for download on our website by March 7, 2015 will be unitholders' Schedule K-1's for the tax year 2015.  For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at 1-800-973-7551.

Conference Call

As announced on January 25, 2016, EV Energy Partners, L.P. will host an investor conference call on February 29, 2016, at 9 a.m. Eastern Standard Time (8 a.m. Central).  Investors interested in participating in the call may dial 1-888-437-9445 (quote conference ID 5107524) at least 5 minutes prior to the start time, or may listen live over the Internet through the Investor Relations section of the EVEP website at http://www.evenergypartners.com

EV Energy Partners, L.P. is a master limited partnership engaged in acquiring, producing and developing oil and gas properties.  More information about EVEP is available on the Internet at http://www.evenergypartners.com.

(code #: EVEP/G)

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Forward Looking Statements

This press release may include statements that are not historical facts which are "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995.  These statements include information about, future plans, our reserve quantities and the present value of our reserves, estimates of maintenance capital and production amounts and other statements which include words such as "anticipates," "plans," "projects," "expects," "intends," "believes," "should," and similar expressions of forward-looking information.  Forward-looking statements are inherently uncertain and necessarily involve risks that may affect the business prospects and performance of EV Energy Partners, L.P. These statements are based on certain assumptions made by EV Energy Partners based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances.  Actual results may differ materially from those contained in the press release.  Such risks and uncertainties include, but are not limited to, changes in commodity prices, changes in reserve estimates, requirements and actions of purchasers of properties, exploration and development activities, the availability and cost of financing, the returns on our capital investments and acquisition strategies, the availability of sufficient cash flow to pay distributions and execute our business plan and general economic conditions.  Additional information on risks and uncertainties that could affect our business prospects and performance are provided in the most recent reports of EV Energy Partners with the Securities and Exchange Commission.  You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release. All forward-looking statements included in this press release are expressly qualified in their entirety by the foregoing cautionary statements.

Any forward-looking statement speaks only as of the date on which such statement is made and EVEP undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

 

Operating Statistics

Three Months Ended December 31,

Twelve Months Ended December 31,

2015

2014

2015

2014

Production data:

Oil (Mbbls)

351

263

1,041

1,052

Natural gas liquids (Mbbls)

655

597

2,326

2,311

Natural gas (Mmcf)

13,266

10,565

43,592

43,363

Net production (Mmcfe)

19,301

15,722

63,792

63,540

Average sales price per unit: (1)

Oil (Bbl)

$ 38.69

$ 69.91

$ 43.67

$ 89.15

Natural gas liquids (Bbl)

13.86

22.54

14.04

28.81

Natural gas (Mcf)

1.86

3.53

2.23

4.02

Mcfe

2.45

4.39

2.74

5.27

Average unit cost per Mcfe:

Production costs:

Lease operating expenses

$ 1.54

$ 1.77

$ 1.56

$ 1.66

Production taxes

0.11

0.16

0.11

0.19

Total

1.65

1.93

1.67

1.85

Depreciation, depletion and amortization

1.62

1.85

1.66

1.67

General and administrative expenses

0.52

0.65

0.62

0.71

(1) Prior to $44.9 million and $14.4 million of net hedge gains on settlements of commodity derivatives for the three months ended December 31, 2015 and December 31, 2014, respectively, and $145.0 million and $8.8 million for the twelve months ended December 31, 2015 and December 31, 2014, respectively.

 

Consolidated Balance Sheets

(In $ thousands, except number of units)

December 31, 2015

December 31, 2014

ASSETS

Current assets:

Cash and cash equivalents

$ 20,415

$ 8,255

Accounts receivable:

Oil, natural gas and natural gas liquids revenues

24,285

32,758

Related party

-

1,043

Other

7,137

4,570

Derivative asset

60,662

113,044

Other current assets

3,057

2,000

Assets held for sale

-

315,173

Total current assets

115,556

476,843

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; December 31, 2015, $971,499; December 31, 2014, $778,679

1,790,455

1,710,925

Other property, net of accumulated depreciation and amortization; December 31, 2015, $970; December 31, 2014, $898

1,019

1,141

Restricted cash

-

33,768

Long–term derivative asset

10,741

20,647

Other assets

5,831

2,837

Total assets

$ 1,923,602

$ 2,246,161

LIABILITIES AND OWNERS' EQUITY

Current liabilities:

Accounts payable and accrued liabilities:

Third party

$ 43,135

$ 47,878

Related party

5,952

-

Income taxes

11,657

-

Total current liabilities

60,744

47,878

Asset retirement obligations

174,003

103,832

Long–term debt, net

688,614

1,027,349

Other long–term liabilities

1,682

989

Commitments and contingencies

Owners' equity:

Common unitholders - 48,871,399 units and 48,572,019 units issued and outstanding as of December 31, 2015 and 2014, respectively

1,011,509

1,077,826

General partner interest

(12,950)

(11,713)

Total owners' equity

998,559

1,066,113

Total liabilities and owners' equity

$ 1,923,602

$ 2,246,161

 

Consolidated Statements of Operations

(In $ thousands, except per unit data)

Three Months Ended  December 31,

Twelve Months Ended December 31,

2015

2014

2015

2014

Revenues:

Oil, natural gas and natural gas liquids revenues

$ 47,354

$ 69,090

$ 175,088

$ 334,729

Transportation and marketing–related revenues

598

1,085

2,883

4,676

Total revenues

47,952

70,175

177,971

339,405

Operating costs and expenses:

Lease operating expenses

29,793

27,779

99,626

105,781

Cost of purchased natural gas

400

808

1,988

3,533

Dry hole and exploration costs

1,975

783

3,695

6,726

Production taxes

2,076

2,462

6,784

11,976

Accretion expense on obligations

2,050

1,201

5,598

4,835

Depreciation, depletion and amortization

31,251

29,112

105,969

106,073

General and administrative expenses

10,026

10,220

38,994

44,955

Impairment of oil and natural gas properties

14,423

111,701

136,667

113,968

Impairment of goodwill

65,924

-

65,924

-

Loss on settlement of contract

1,210

-

1,210

-

Gain on sales of oil and natural gas properties

(20)

(31,835)

(551)

(33,319)

Total operating costs and expenses

159,108

152,231

465,904

364,528

Operating loss

(111,156)

(82,056)

(287,933)

(25,123)

Other income, net:

Gain on derivatives, net

26,739

102,984

78,145

99,720

Interest expense

(12,057)

(14,385)

(50,336)

(52,578)

Gain on early extinguishment of debt

24,024

-

24,024

-

Other income, net

27

246

78

702

Total other income, net

38,733

88,845

51,911

47,844

(Loss) income from continuing operations before income taxes

(72,423)

6,789

(236,022)

22,721

Income taxes

1,159

(652)

1,843

(476)

(Loss) income from continuing operations

(71,264)

6,137

(234,179)

22,245

Income from discontinued operations

-

96,239

255,512

107,475

Net (loss) income

($ 71,264)

$ 102,376

$ 21,333

$ 129,720

Basic and diluted earnings per limited partner unit:

(Loss) income from continuing operations

($ 1.43)

$ 0.11

($ 4.72)

$ 0.41

Income from discontinued operations

-

$ 1.92

$ 5.13

$ 2.17

Net (loss) income

($ 1.43)

$ 2.03

$ 0.41

$ 2.58

Weighted average limited partner units outstanding (basic and diluted)

48,871

48,572

48,853

48,563

Distributions declared per unit

$ 0.075

$ 0.500

$ 1.575

$ 2.819

 

Consolidated Statements of Cash Flows

(In $ thousands)

Twelve Months Ended December 31,

2015

2014

Cash flows from operating activities:

Net income

$ 21,333

$ 129,720

Adjustments to reconcile net income to net cash flows provided by operating activities:

Income from discontinued operations

(255,512)

(107,475)

Amortization of volumetric production payment liability

(1,196)

-

Accretion expense on obligations

5,598

4,835

Depreciation, depletion and amortization

105,969

106,073

Equity–based compensation

12,001

19,289

Impairment of oil and natural gas properties

136,667

113,968

Impairment of goodwill

65,924

-

Gain on sales of oil and natural gas properties

(551)

(33,319)

Gain on derivatives, net

(78,145)

(99,720)

Cash settlements of matured derivative contracts

140,657

5,313

Gain on early extinguishment of debt

(24,024)

-

Deferred taxes

(13,285)

-

Other

4,487

5,703

Changes in operating assets and liabilities, net of effects of amounts acquired:

Accounts receivable

14,850

3,275

Other current assets

511

(1,203)

Accounts payable and accrued liabilities

(4,067)

2,368

Income taxes

10,683

-

Other, net

(245)

(627)

Net cash flows provided by operating activities from continuing operations

141,655

148,200

Net cash flows used in operating activities from discontinued operations

(372)

-

Net cash flows provided by operating activities    

141,283

148,200

Cash flows from investing activities:

Acquisitions of oil and natural gas properties, net of cash acquired

(250,357)

-

Additions to oil and natural gas properties 

(67,923)

(102,761)

Prepaid drilling costs

-

(2,501)

Proceeds from sales of oil and natural gas properties

1,457

45,183

Restricted cash

33,768

(33,768)

Cash settlements from acquired derivative contracts

2,615

-

Other

73

48

Net cash flows used in investing activities from continuing operations

(280,367)

(93,799)

Net cash flows provided by investing activities from discontinued operations

572,160

46,985

Net cash flows provided by (used in) investing activities

291,793

(46,814)

Cash flows from financing activities:

Long-term debt borrowings

295,000

209,000

Repayment of long-term debt borrowings

(561,000)

(159,000)

Redemption of 8% Senior Notes due 2019

(49,954)

-

Loan costs paid

(4,074)

-

Contributions from general partner

91

154

Distributions paid

(100,979)

(154,978)

Other

-

(5)

Net cash flows used in financing activities

(420,916)

(104,829)

Increase (decrease) in cash and cash equivalents

12,160

(3,443)

Cash and cash equivalents – beginning of period

8,255

11,698

Cash and cash equivalents – end of period

$ 20,415

$ 8,255

 

Non GAAP Measures

We define Adjusted EBITDAX as net (loss) income plus income from discontinued operations, EBITDAX from discontinued operations, income taxes, interest expense, net, cash settlements of matured interest rate swaps, depreciation, depletion and amortization, accretion expense on obligations, amortization of volumetric production payment (VPP), gain on derivatives, net, cash settlements of matured derivative contracts, non-cash equity-based compensation, impairment of oil and natural gas properties, impairment of goodwill, non-cash inventory write down expense, dry hole and exploration costs, gain on sales of oil and natural gas properties, loss on settlement of contract, gain on early extinguishment of debt, and loss on sale of investment in unconsolidated affiliates, contained in Other income, net. Distributable Cash Flow is defined as Adjusted EBITDAX less cash income taxes, cash interest expense, net, realized losses on interest rate swaps, and estimated maintenance capital expenditures.

Adjusted EBITDAX and Distributable Cash Flow are used by our management to provide additional information and statistics relative to the performance of our business, including (prior to the creation of any reserves) the cash available to pay distributions to our unitholders. We believe these financial measures may indicate to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDAX and Distributable Cash Flow are also quantitative standards used throughout the investment community with respect to performance of publicly-traded partnerships. Adjusted EBITDAX and Distributable Cash Flow should not be considered as alternatives to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDAX and Distributable Cash Flow exclude some, but not all, items that affect net income and operating income and these measures may vary among companies. Therefore, our Adjusted EBITDAX and Distributable Cash Flow may not be comparable to similarly titled measures of other companies.

 

Reconciliation of Net (Loss) Income to Adjusted EBITDAX and Distributable Cash Flow

(In $ thousands)

Three Months Ended  December 31,

Twelve Months Ended  December 31,

2015

2014

2015

2014

Net (loss) income

($ 71,264)

$ 102,376

$ 21,333

$ 129,720

Add:

Income from discontinued operations

-

(96,239)

(255,512)

(107,475)

EBITDAX from discontinued operations

-

7,874

15,941

25,641

Income taxes

(1,159)

652

(1,843)

476

Interest expense, net

12,050

14,385

50,314

52,577

Cash settlements of matured interest rate swaps

-

888

1,736

3,523

Depreciation, depletion and amortization

31,251

29,112

105,969

106,073

Accretion expense on obligations

2,050

1,201

5,598

4,835

Amortization of VPP

(1,196)

-

(1,196)

-

Gain on derivatives, net

(26,739)

(102,984)

(78,145)

(99,720)

Cash settlements of matured derivative contracts

44,904

13,483

143,272

5,313

Non-cash equity-based compensation

2,366

3,944

12,001

19,289

Impairment of oil and natural gas properties

14,423

111,701

136,667

113,968

Impairment of goodwill

65,924

-

65,924

-

Non-cash inventory write down expense

973

82

1,122

136

Dry hole and exploration costs

1,975

783

3,695

6,726

Gain on sales of oil and natural gas properties

(20)

(31,834)

(551)

(33,319)

Loss on settlement of contract

1,210

-

1,210

-

Gain on early extinguishment of debt

(24,024)

-

(24,024)

-

Loss on sale of investment in unconsolidated affiliates, contained in Other income, net

-

-

358

-

Adjusted EBITDAX

$ 52,724

$ 55,424

$ 203,869

$ 227,763

Less:

Cash income taxes

441

165

441

448

Cash interest expense, net

11,264

13,777

48,504

50,151

Realized losses on interest rate swaps

-

888

1,736

3,523

Estimated maintenance capital expenditures (1)

14,875

15,354

54,672

61,242

Distributable Cash Flow

$ 26,144

$ 25,240

$ 98,516

$ 112,399

(1) Estimated maintenance capital expenditures are those expenditures estimated to be necessary to maintain the production levels of our oil and gas properties over the long term and the operating capacity of our other assets over the long term.

 

Hedge Summary as of February 29, 2015

 Swap 

 Swap 

Period

Index

 Volume 

 Price 

Natural Gas (Mmmbtus)

2016

NYMEX

39,894.0

$3.57

2017

NYMEX

21,900.0

$3.24

Crude (Mbbls)

2016

WTI

366.0

$90.14

Ethane (Mbbls)

2016

Mt Belvieu

3.7

$9.14

Interest Rate Swap Agreements

 Notional Amount 

Fixed Rate

 (in $ mill) 

January 2017 - December 2017

100.0

1.039%

January 2018 - September 2020

100.0

1.795%

 

EV Energy Partners, L.P., Houston Nicholas Bobrowski 713-651-1144 http://www.evenergypartners.com

 

SOURCE EV Energy Partners, L.P.



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