Atlas Resource Partners, L.P. Reports Operating And Financial Results For The First Quarter 2014

ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except per unit data)

Three Months Ended

March 31,

2014

2013

Revenues:

Gas and oil production

$      96,245

$     46,064

Well construction and completion

49,377

56,478

Gathering and processing

4,468

3,585

Administration and oversight

1,729

1,085

Well services

5,479

4,816

Other, net

47

20

          Total revenues

157,345

112,048

Costs and expenses:

Gas and oil production

36,792

15,216

Well construction and completion

42,936

49,112

Gathering and processing

4,413

4,413

Well services     

2,482

2,318

General and administrative

16,455

17,567

Depreciation, depletion and amortization

50,237

21,208

          Total costs and expenses

153,315

109,834

Operating income

4,030

2,214

Loss on asset sales and disposal

(1,603)

(702)

Interest expense

(13,188)

(6,889)

Net loss

(10,761)

(5,377)

Preferred limited partner dividends

(4,399)

(1,957)

Net loss attributable to common limited partners and the general partner

$    (15,160)

$      (7,334)

Allocation of net loss attributable to common limited partners and the general partner:

General partner's interest

$       2,004

$          301

Common limited partners' interest

(17,164)

(7,635)

Net loss attributable to common limited partners and the general partner

$    (15,160)

$      (7,334)

Net loss attributable to common limited partners per unit:

Basic and Diluted

$        (0.28)

$        (0.17)

Weighted average common limited partner units outstanding:

Basic and Diluted

61,219

43,974

ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)

March 31,

December 31,

ASSETS

2014

2013

Current assets:

      Cash and cash equivalents

$             1,965

$             1,828

      Accounts receivable

78,127

58,822

      Current portion of derivative asset

161

1,891

      Subscriptions receivable

—

47,692

      Prepaid expenses and other

17,481

10,097

          Total current assets

97,734

120,330

Property, plant and equipment, net

2,125,189

2,120,818

Goodwill and intangible assets, net

32,679

32,747

Long-term derivative asset

23,749

27,084

Other assets, net

42,554

42,821

$     2,321,905

$     2,343,800

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:

      Accounts payable      

$           94,472

$           69,346

      Advances from affiliates

24,413

26,742

      Liabilities associated with drilling contracts

—

49,377

      Current portion of derivative liability

22,372

6,353

      Accrued well drilling and completion costs

66,199

40,481

      Accrued liabilities

38,961

51,416

          Total current liabilities

246,417

243,715

Long-term debt

889,388

942,334

Asset retirement obligations and other

92,110

90,460

Commitments and contingencies

Partners' Capital:

      General partner's interest

1,485

4,482

      Preferred limited partners' interests

180,543

183,477

      Common limited partners' interests

905,888

852,457

      Class C preferred limited partner warrants

1,176

1,176

      Accumulated other comprehensive income

4,898

25,699

Total partners' capital

1,093,990

1,067,291

$      2,321,905

$      2,343,800

ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
(unaudited)

Three Months Ended

March 31,

2014

2013

Net loss attributable to common limited partners per unit - basic

$         (0.28)

$          (0.17)

Cash distributions paid per unit ⁽¹⁾

$          0.58

$           0.51

Production revenues (in thousands):

Natural gas

$     74,190

$       29,056

Oil

12,283

8,806

Natural gas liquids

9,772

8,202

Total production revenues

$     96,245

$       46,064

Production volume:⁽²⁾⁽³⁾

Appalachia: ⁽⁴⁾

Natural gas (Mcfd)

41,146

31,568

Oil (Bpd)

415

278

Natural gas liquids (Bpd)

29

2

Total (Mcfed)

43,810

33,244

Raton/Black Warrior^{: (4)}

Natural gas (Mcfd)

108,368

—

Oil (Bpd)

—

—

Natural gas liquids (Bpd)

—

—

Total (Mcfed)

108,368

—

Barnett/Marble Falls^:

Natural gas (Mcfd)

57,898

66,069

Oil (Bpd)

834

780

Natural gas liquids (Bpd)

2,570

2,557

Total (Mcfed)

78,319

86,092

Mississippi Lime/Hunton:

Natural gas (Mcfd)

5,873

4,757

Oil (Bpd)

301

29

Natural gas liquids (Bpd)

485

243

Total (Mcfed)

10,587

6,393

Other Operating Areas:⁽⁴⁾

Natural gas (Mcfd)

3,402

4,861

Oil (Bpd)

19

14

Natural gas liquids (Bpd)

338

394

Total (Mcfed)

5,544

7,311

Total Production:⁽³⁾

Natural gas (Mcfd)

216,688

107,255

Oil (Bpd)

1,568

1,101

Natural gas liquids (Bpd)

3,422

3,197

Total (Mcfed)

246,628

133,039

Average sales prices: ⁽³⁾

Natural gas (per Mcf) ⁽⁵⁾

$           4.07

$           3.33

Oil (per Bbl)⁽⁶⁾

$         87.04

$         88.89

Natural gas liquids (per Bbl) ⁽⁷⁾

$         31.73

$         28.51

Production costs:⁽³⁾⁽⁸⁾

        Lease operating expenses per Mcfe

$           1.17

$           0.97

Production taxes per Mcfe

0.27

0.22

Transportation and compression expenses per Mcfe

0.29

0.16

Total production costs per Mcfe

$           1.73

$           1.35

Depletion per Mcfe⁽³⁾

$           2.16

$           1.64

⁽¹⁾  

Represents the cash distributions declared per limited partner unit for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.

⁽²⁾  

Production quantities consist of the sum of (i) ARP's proportionate share of production from wells in which it has a direct interest, based on ARP's proportionate net revenue interest in such wells, and (ii) ARP's proportionate share of production from wells owned by the investment partnerships in which ARP has an interest, based on its equity interest in each such partnership and based on each partnership's proportionate net revenue interest in these wells.

⁽³⁾  

"Mcf" and "Mcfd" represent thousand cubic feet and thousand cubic feet per day; "Mcfe" and "Mcfed" represent thousand cubic feet equivalents and thousand cubic feet equivalents per day, and "Bbl" and "Bpd" represent barrels and barrels per day.  Barrels are converted to Mcfe using the ratio of six Mcf's to one barrel.

⁽⁴⁾ 

Appalachia includes ARP's production located in Pennsylvania, Ohio, New York and West Virginia; Raton/Black Warrior includes ARP's production located in the Raton Basin in northern New Mexico and the Black Warrior Basin in central Alabama; Other operating areas include ARP's production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.

⁽⁵⁾ 

ARP's average sales prices for natural gas before the effects of financial hedging were $4.68 per Mcf and $2.90 per Mcf for the three months ended March 31, 2014 and 2013, respectively. These amounts exclude the impact of subordination of production revenues to investor partners within the investor partnerships.  Including the effects of subordination, average natural gas sales prices were $3.80 per Mcf ($4.42 per Mcf before the effects of financial hedging) and $3.01 per Mcf ($2.59 per Mcf before the effects of financial hedging) for the three months ended March 31, 2014 and 2013, respectively.

⁽⁶⁾  

ARP's average sales prices for oil before the effects of financial hedging were $93.18 per barrel and $90.80 per barrel for the three months ended March 31, 2014 and 2013, respectively.

⁽⁷⁾ 

ARP's average sales prices for natural gas liquids before the effects of financial hedging were $35.65 per barrel and $28.74 per barrel for the three months ended March 31, 2014 and 2013, respectively.

⁽⁸⁾  

Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance, production overhead and transportation expenses. These amounts exclude the effects of ARP's proportionate share of lease operating expenses associated with subordination of production revenue to investor partners within ARP's investor partnerships. Including the effects of these costs, lease operating expenses per Mcfe were $1.10 per Mcfe ($1.66 per Mcfe for total production costs) and $0.90 per Mcfe ($1.27 per Mcfe for total production costs) for the three months ended March 31, 2014 and 2013, respectively.

ATLAS RESOURCE PARTNERS, L.P.
CAPITALIZATION INFORMATION
(unaudited; in thousands)

March 31,

2014

December 31,
2013

Total debt

$         889,388

$         942,334

Less:  Cash

(1,965)

(1,828)

Total net debt/(cash)

887,423

940,506

Partners' capital 

1,093,990

1,067,291

Total capitalization

$     1,981,413

$     2,007,797

Ratio of net debt to capitalization

0.45x

0.47x

ATLAS RESOURCE PARTNERS, L.P.
CAPITAL EXPENDITURE DATA
(unaudited; in thousands)

Three Months Ended

March 31,

2014

Maintenance capital expenditures⁽¹⁾

$      10,800

$         4,000

Expansion capital expenditures

29,097

54,487

        Total

$      39,897

$      58,487

⁽¹⁾

Oil and gas assets naturally decline in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing its Distributable Cash Flow and cash distributions, which it refers to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions. ARP considers expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures – generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures.

ATLAS RESOURCE PARTNERS, L.P.
Financial Information
(unaudited; in thousands, except per unit amounts)

Three Months Ended

March 31,

Reconciliation of net loss to non-GAAP measures⁽¹⁾:

2014

2013

Net loss

$     (10,761)

$      (5,377)

Acquisition and related costs

2,379

3,714

Depreciation, depletion and amortization

50,237

21,208

Amortization of deferred finance costs

1,812

4,642

Non-cash stock compensation expense

2,345

4,247

Maintenance capital expenditures⁽²⁾

(10,800)

(4,000)

Loss on asset sales and disposal

1,603

702

Other

(3)

−

Distributable cash flow attributable to limited partners and the

general partner⁽¹⁾

$      36,812

$      25,136

Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:

Gas and oil production margin

$      59,453

$      30,848

Well construction and completion margin

6,441

7,366

Administration and oversight margin

1,729

1,085

Well services margin

2,997

2,498

Gathering

55

(828)

Cash general and administrative expenses⁽³⁾

(11,731)

(9,606)

Other, net

44

20

Adjusted EBITDA⁽¹⁾

58,988

31,383

Cash interest expense⁽⁴⁾

(11,376)

(2,247)

Maintenance capital expenditures⁽²⁾

(10,500)

(4,000)

Distributable Cash Flow attributable to limited partners and the

     general partner⁽¹⁾

$      37,112

$      25,136

Discretionary adjustments considered by the Board of Directors of the General Partner in the

    determination of quarterly cash distributions:

Net cash from acquisitions from the effective date through closing date⁽⁵⁾

5,197

−

Distributable Cash Flow with discretionary adjustments by the Board of

     Directors of the General Partner⁽⁶⁾

$      42,309

$      25,136

Distributions Paid⁽⁷⁾

$      45,731

$      25,330

  per limited partner unit

$          0.58

$          0.51

Excess (shortfall) of distributable cash flow with discretionary

   adjustments by the Board of Directors of the General Partner after

   distributions to unitholders⁽⁸⁾

$       (3,422)

$         (194)

(1)

Although not prescribed under generally accepted accounting principles ("GAAP"), ARP's management believes the presentation of EBITDA, Adjusted EBITDA and Distributable Cash Flow ("DCF") is relevant and useful because it helps ARP's investors understand its operating performance, allows for easier comparison of its results with other master limited partnerships ("MLP"), and is a critical component in the determination of quarterly cash distributions.  As a MLP, ARP is required to distribute 100% of available cash, as defined in its limited partnership agreement ("Available Cash") and subject to cash reserves established by its general partner, to investors on a quarterly basis.  ARP refers to Available Cash prior to the establishment of cash reserves as DCF.  EBITDA, Adjusted EBITDA and DCF should not be considered in isolation of, or as a substitute for, net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity.  While ARP's management believes that its methodology of calculating EBITDA, Adjusted EBITDA and DCF is generally consistent with the common practice of other MLPs, such metrics may not be consistent and, as such, may not be comparable to measures reported by other MLPs, who may use other adjustments related to their specific businesses.  EBITDA, Adjusted EBITDA and DCF are supplemental financial measures used by the ARP's management and by external users of ARP's financial statements such as investors, lenders under ARP's credit facility, research analysts, rating agencies and others to assess its:
- Operating performance as compared to other publicly traded partnerships and other companies in the upstream energy sector, without regard to financing methods, historical cost basis or capital structure;
- Ability to generate sufficient cash flows to support its distributions to unitholders;
- Ability to incur and service debt and fund capital expansion;
- The viability of potential acquisitions and other capital expenditure projects; and
- Ability to comply with financial covenants in its Amended Credit Facility, which is calculated based upon Adjusted EBITDA.

DCF is determined by calculating EBITDA, adjusting it for non-cash, non-recurring and other items to achieve Adjusted EBITDA, and then deducting cash interest expense and maintenance capital expenditures.  ARP defines EBITDA as net income (loss) plus the following adjustments:
- Interest expense;
- Income tax expense;
- Depreciation, depletion and amortization. 

ARP defines Adjusted EBITDA as EBITDA plus the following adjustments:
- Asset impairments;
- Acquisition and related costs;
- Non-cash stock compensation;
- (Gains) losses on asset disposal;
- Cash proceeds received from monetization of derivative transactions;
- Premiums paid on swaption derivative contracts; and
- Other items.

ARP adjusts DCF for non-cash, non-recurring and other items for the sole purpose of evaluating its cash distribution for the quarterly period, with EBITDA and Adjusted EBITDA adjusted in the same manner for consistency.  ARP defines DCF as Adjusted EBITDA less the following adjustments:
- Cash interest expense; and
- Maintenance capital expenditures.

(2)

Production from oil and gas assets naturally declines in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such declines in production margin for the purpose of stabilizing its DCF and cash distributions, which it refers to as maintenance capital expenditures.  ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells.  Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year.  ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased.  Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs.  Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions.  ARP considers expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures – generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures.

(3)

Excludes non-cash stock compensation expense and certain acquisition and related costs.

(4)

Excludes non-cash amortization of deferred financing costs.

(5)

These amounts reflect net cash proceeds received from the respective effective date through the respective closing date of assets acquired, less estimated and pro forma amounts of maintenance capital expenditures and financing costs.  The management of ARP believes these amounts are critical in its evaluation of DCF and cash distributions for the period.  Under GAAP, such amounts are characterized as purchase price adjustments and are reflected in the net purchase price paid for the acquired assets, rather than reflected as components of net income or loss for the period.  For the 1st quarter 2014, such amounts include net cash generated by the GeoMet assets from January 1, 2014 to March 31, 2014 of $5.5 million, less estimated maintenance capital expenditures of $0.3 million. 

(6)

Including the discretionary adjustments by the Board of Directors of the General Partner in the determination of quarterly cash distributions, Adjusted EBITDA would have been $64.5 million for the three months ended March 31, 2014.

(7)

Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.

(8)

ARP seeks to at least maintain its current cash distribution in future quarterly periods, and expects to only increase such cash distributions when future Distributable Cash Flow amounts allow for it and are expected to be sustained.  The Partnership's determination of quarterly cash distributions and its resulting determination of the amount of excess (shortfall) those cash distributions generate in comparison to Distributable Cash Flow are based upon its assessment of numerous factors, including but not limited to future commodity price and interest rate movements, variability of well productivity, weather effects, and financial leverage.  ARP also considers its historical trailing four quarters of excess or shortfalls and future forecasted excess or shortfalls that its cash distributions generate in comparison to Distributable Cash Flow due to the variability of its Distributable Cash Flow generated each quarter, which could cause it to have more or less excess (shortfalls) generated from quarter to quarter. 

ATLAS RESOURCE PARTNERS, L.P.
Hedge Position Summary
(as of May 7, 2014)

Natural Gas

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

   2014^(b)

$    4.15

45,114,732

2015

$    4.24

51,924,492

2016

$    4.31

45,746,320

2017

$    4.53

24,840,000

2018

$    4.72

3,960,000

Costless Collars

Average

Average

Production Period

Floor Price

Ceiling Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(per mmbtu)^(a)

(mmbtus)^(a)

   2014^(b)

$    4.22

$    5.12

2,880,000

2015

$    4.23

$    5.13

3,480,000

Put Options – Drilling
Partnerships

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

   2014^(b)

$    3.80

1,350,000

2015

$    4.00

1,440,000

2016

$    4.15

1,440,000

WAHA Basis Swaps

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

   2014^(b)

$    (0.110)

8,100,000

Natural Gas Liquids

Crude Oil Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per bbl)^(a)

(bbls)^(a)

   2014^(b)

$    91.57

79,500

2015

$    88.55

96,000

2016

$    85.65

84,000

2017

$    83.78

60,000

Mt Belvieu Ethane Purity Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

   2014^(b)

$    0.3025

45,000

Mt Belvieu Propane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

   2014^(b)

$    0.9996

220,500

2015

$    1.0161

192,000

Mt Belvieu Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

   2014^(b)

$    1.3075

27,000

2015

$    1.2481

36,000

Mt Belvieu Iso-Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

   2014^(b)

$    1.3225

27,000

2015

$    1.2631

36,000

Crude Oil

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per bbl)^(a)

(bbls)^(a)

   2014^(b)

$    92.69

409,500

2015

$    88.14

567,000

2016

$    85.52

225,000

2017

$    83.30

132,000

Costless Collars

Average

Average

Production Period

Floor Price

Ceiling Price

Volumes

(per bbl)^(a)

(per bbl)^(a)

(bbls)^(a)

   2014^(b)

$    84.17

$  113.31

30,870

2015

$    83.85

$  110.65

29,250

^(a)

"mmbtu" represents million metric British thermal units.; "bbl" represents barrel.

^(b)

Reflects hedges covering the last nine months of 2014.