SOURCE: Quest Energy Partners, L.P.

March 11, 2008 01:00 ET

Quest Energy Partners Reports Fourth Quarter 2007 Results and Provides 2008 Guidance

OKLAHOMA CITY, OK--(Marketwire - March 11, 2008) - Quest Energy Partners L.P. (NASDAQ: QELP) a natural gas and oil and gas master limited partnership (MLP) that was formed from the contribution of certain natural gas and oil producing properties from Quest Resource Corporation (NASDAQ: QRCP), today announced unaudited results for its fourth quarter 2007 and provided updated guidance for full year 2008.

The Partnership's fourth quarter began on November 15, 2007, when its initial public offering was completed, and ended on December 31, 2007. This unaudited financial information provided in this release is preliminary and subject to adjustments in connection with the final audited financial statements to be released on or about March 30, 2008 within the Partnership's Annual Report on Form 10-K.

Adjusted earnings before interest, income taxes, depreciation and amortization (Adjusted EBITDA), a non-GAAP measure, totaled $6.4 million for the period. A distribution of $4.4 million was paid on February 14, 2008 to unitholders of record at the close of business on February 7, 2008 based on an annualized distribution rate of $1.60 per unit. Adjusted EBITDA is reconciled to Net Income and Net Cash from Operating Activities, its most directly comparable GAAP measures in the attached financial schedules.

The net loss for the period totaled $18.5 million as results were impacted by approximately $13.1 million of interest expense associated with the Partnership's early retirement of debt with proceeds from its initial public offering and a $6.1 million unrealized loss on derivative instruments.

Management Comment

"We are pleased to have completed the Partnership's initial public offering in November and paid our first distribution in February, and look forward to generating solid returns for our unitholders over the long term," said Jerry Cash, Chairman, President, and Chief Executive Officer of the general partner of Quest Energy Partners. "We recently added 0.7 million barrels of oil reserves with the completion of the Partnership's first acquisition in February 2008 and based on the expected production gains from the 575 new wells connected in 2007 and our 325 well program for 2008, we are well positioned to generate internal distribution growth. In addition, we continue to opportunistically pursue attractive external opportunities to grow distributions."

Expected Distributions

In early February 2008, the Partnership purchased certain oil producing properties in Oklahoma for $9.5 million. The acquisition was financed with borrowings under the Partnership's credit facility. In conjunction with the acquisition, the Partnership reduced its 2008 Cherokee Basin land leasing budget of $19 million by approximately 50% to keep its total capital budget unchanged at $78.5 million. The reduction reflected a strategic decision to invest a greater percentage of capital in projects that provide an immediate benefit to distributable cash flow while still maintaining a large drilling inventory that allows the Partnership to drive sustainable organic production growth.

As a result of the accretive cash flows from the acquisition, a higher natural gas futures curve, and a positive production trend, the Partnership's management expects to recommend to the Board of Directors of Quest Energy Partners GP LLC an increase in the partnership's current annualized distribution rate of $1.60 per unit.

Operating Performance

Quest Energy Partners was formed with the contribution of substantially all of the oil and gas assets of Quest Resource Corporation and as a result the following discussion reflects combined historical performance of Quest Resource prior to November 15, 2007 and the Partnership from November 15, 2007 through December 31, 2007.


Total natural gas equivalent production of the Partnership and its predecessor averaged 52.3 million cubic feet equivalents (Mmcfe) per day for fourth quarter 2007, a 33% increase from an average of 39.4 Mmcfe per day from the fourth quarter 2006. The increase was driven by the successful execution of Quest's development program in 2007.

Operating Costs

Total production costs, excluding gross production and ad valorem taxes, were $1.27 per Mcfe for 2007 down from $1.29 per Mcfe in 2006. On a quarterly basis, production cost per Mcfe declined from $1.41 in the first quarter of 2007 to $1.19 in the fourth quarter. This decrease was the result of rising production volumes and the benefits from certain cost cutting initiatives. The Partnership expects to continue to benefit from these programs and rising volumes in 2008 and anticipates production costs, excluding gross production and ad valorem taxes, of $1.05 per Mcfe to $1.15 per Mcfe for the full year.


Total year-end 2007 proved reserves were 211.1 billion cubic feet of natural gas equivalents (bcfe), a 7% increase over the year-end 2006 proved reserves of its predecessor. These proved reserves had a Standardized Measure of $322.5 million. Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined using prices and costs in effect as of the date of estimation and discounted using an annual discount rate of 10%. Approximately 99% of the company's proved reserves were natural gas; approximately 67% of which were proved developed and 33% of which were proved undeveloped. The increase in proved reserves was driven by the 2007 drilling and development program and does not include the estimated 0.71 million barrels of total proved oil reserves added to the Partnership as a result of the previously announced acquisition which closed in early February.

The Partnership's reserves are long-lived, with an average proved reserve-to-production ratio of 12.3 years (8.2 years for its proved developed properties) as of December 31, 2007. The Partnership's typical Cherokee Basin coalbed methane (CBM) well has a predictable production profile and a standard economic life of approximately 15 years.

Drilling and Completion Activity

The Partnership and its predecessor completed a total of 125 gross wells in the Cherokee Basin in the fourth quarter 2007 and 575 for the full year 2007. The Partnership had interests in approximately 2,254 net wells on December 31, 2007, up from the 1,682 gross wells operated by its predecessor on December 31, 2006. The Partnership plans to complete 325 gross wells in 2008, or approximately 27 per month.

Acreage and Drilling Locations

At December 31, 2007, the Partnership had the right to develop approximately 558,000 net acres in the Cherokee Basin, of which approximately 48% were undeveloped. The Partnership has identified approximately 2,100 gross drilling locations on its acreage in the Cherokee Basin, of which approximately 800 were classified as proved undeveloped. These locations represent an approximate six and a half year inventory of drilling activity at the planned 2008 level of 325 wells.

Management Guidance

The Partnership provided the following guidance with respect to certain financial and operation metrics for the first quarter and full year 2008. The guidance takes into account the impact of the acquisition that closed in early-February.

                                           1Q08E              FY 2008E
                                     -----------------   ------------------
Total Production (Bcfe)                 5.0  -   5.5        22.0  -  25.0

Avg Daily Production (MMcfe/d)         55.0  -  60.0        60.0  -  68.0

Total Operating Expenses ($mm)         17.0  -  19.0        74.0  -  82.0

General & Administrative ($mm)          1.8  -   2.2        10.0  -  12.0

Adjusted EBITDA ($mm)                  16.4  -  18.2        72.0  -  80.0

Net Interest Expense ($mm)              2.0  -   2.2        10.0  -  11.0

Sustaining Capital Expenditures ($mm)   4.8  -   5.3        21.0  -  23.0

Distributable Cash Flow ($mm)           9.6  -  10.7        41.0  -  46.0

Distributable Cash Flow per unit       0.44  -  0.50        1.90  -  2.13

Distribution Coverage                  1.1x  -  1.2x        1.2x  -  1.3x

% of Total Production Hedged            65%      71%         58%       65%

Avg Realized Gas Hedge Price ($/MMBtu)      6.90                 6.90

Avg Realized Oil Hedge Price ($/bbl)       93.00                93.00

Unhedged Production Pricing Assumptions
NYMEX Gas Price ($/MMBtu)                   8.00                 8.00

NYMEX Gas Price Differential %           8%  -   12%          8%  -    12%

NYMEX Oil Price ($/bbl)                    80.00                80.00

NYMEX Oil Price Differential %           2%  -   4%           2%  -    4%

The ranges for Adjusted EBITDA are based on oil and gas sales equal to the anticipated range of production, its existing derivative contracts for hedged volumes, and, for unhedged volumes, the assumed NYMEX Gas and Oil Prices listed above less an assumed NYMEX Gas and Oil Price differential (which is the difference between NYMEX Gas and Oil Prices and the price received at the major pipeline delivery point). Management currently believes the assumed prices and differentials to NYMEX are reasonable based on historical levels and management experience. However, due to market conditions and other factors outside the Partnership's control, the actual prices and differentials realized by the Partnership will be different and those differences may be material. On March 10, 2008, the closing spot price at Henry Hub (the pricing point for NYMEX) was $9.59/MMBtu and the differential from the Southern Star natural gas price was 10% or $0.96/MMBtu.

Conference Call

Quest will host a conference call to discuss 2007 fourth quarter and full year operating and financial results on Tuesday, March 11, 2008 at 11:00 a.m. Eastern time. There will be a question and answer period following the presentation.

Call:      877-440-5786 (US/Canada) and 719-325-4915 (International)
           Passcode: 9940524

Internet:  Live and rebroadcast over the Internet:  simply log on to

Replay:    Available through March 22, 2008 at 888-203-1112 (US/Canada) and
           719-457-0820 (International) using passcode 9940524 and at

About Quest Energy Partners L.P.

Quest Energy Partners, L.P. was formed by Quest Resource Corporation (NASDAQ: QRCP) to acquire, exploit and develop natural gas and oil properties and to acquire, own, and operate related assets. The Partnership owns more than 2,300 wells and is the largest producer of natural gas in the Cherokee Basin, which is located in southeast Kansas and northeast Oklahoma and holds a drilling inventory of approximately 2,100 locations. For more information, visit the Quest Energy Partners website at

Quest Resource Corporation is a fully integrated E&P company that owns 100% of the general partner and a 57% limited partner interest in Quest Energy Partners, L.P. and 85% of the general partner and a 36% limited partner interest in Quest Midstream Partners, L.P. Quest Resource operates and controls Quest Energy Partners and Quest Midstream Partners through its ownership of their general partners. For more information, visit the Quest Resource website at

Quest Midstream Partners, L.P. was formed by Quest Resource Corp. to acquire and develop transmission and gathering assets in the midstream natural gas and oil industry. The partnership owns approximately 2,000 miles of natural gas gathering pipelines and over 1,100 miles of interstate natural gas transmission pipelines in Oklahoma, Kansas, and Missouri. For more information, visit the Quest Midstream Partners website at

Forward-Looking Statements

Opinions, forecasts, projections or statements other than statements of historical fact, are forward-looking statements that involve risks and uncertainties. Forward-looking statements in this announcement are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Although the Partnership believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. In particular, the forward-looking statements made in this release are based upon a number of financial and operating assumptions that are subject to a number of risks, including without limitation: the uncertainty involved in exploring for and developing new natural gas reserves, the sale prices of natural gas and oil, labor and raw material costs, the availability of sufficient capital resources to carry out the Partnership's anticipated level of new well development and Quest Midstream's construction of related pipelines, environmental issues, weather conditions, competition, general market conditions. Actual results may differ materially due to a variety of factors, some of which may not be foreseen by Quest. These risks, and other risks are detailed in the Partnership's filings with the Securities and Exchange Commission. You can find the Partnership's filings with the Securities and Exchange Commission at or at By making these forward-looking statements, the Partnership undertakes no obligation to update these statements for revisions or changes after the date of this release.

               Quest Energy Partners, L.P. and Subsidiaries
                 Statements of Operations (in $thousands)

                                                   Inception (November 15,
                                                 through December 31, 2007
Oil and gas sales                                                   15,842
Other revenue and expense                                               22
Total revenues                                                      15,864

Costs and Expenses
Oil and gas production                                               3,579
Pipeline operating                                                   4,342
General and administrative                                           1,562
Depreciation, depletion and amortization                             5,046
Total costs and expenses                                            14,529

Operating Income (Loss)                                              1,335

Other income (expense)
Change in derivative fair value                                     (6,082)
(Loss)/gain on sale of assets                                          (18)
Interest expense                                                   (13,760)
Interest income                                                         14
Total other income and expense                                     (19,846)

Loss before income taxes                                           (18,511)
Income tax expense                                                       0
Net Loss                                                           (18,511)

General partner's interest in net loss                                (370)
Limited partners' interest in net income                           (18,141)

Net loss per limited partner unit                                    (0.86)

Weighted average limited partner units
 outstanding                                                    21,159,502

               Quest Energy Partners, L.P. and Subsidiaries
        Selected balance sheet data (at period end, in $thousands):

                                                    December 31, 2007
Cash and cash equivalents                                10,170
Property and equipment, net                             298,021
Total assets                                            359,251
Total debt                                               95,374
Total members' equity                                   228,762

               Quest Energy Partners, L.P. and Subsidiaries
                 Statements of Cash Flows (in $thousands)

                                                   Inception (November 15,
                                                 through December 31, 2007
Cash flows from operating activities:
Net (loss)                                                         (18,511)
Other                                                               12,681
Net operating cash flows prior to working
 capital changes                                                    (5,830)

Change in assets and liabilities:                                 (257,854)
Net cash provided by (used in) operating
 activities                                                       (263,684)

Net cash used in investing activities                               (7,603)

Net cash provided by (used in) financing
 activities                                                        281,457

Net increase (decrease) in cash                                     10,170

Cash, beginning of period                                                0
Cash, end of period                                                 10,170

Reconciliation of Non-GAAP Financial Measures

Adjusted EBITDA is defined as net income (loss) plus:

--  net interest expense;
--  depreciation, depletion and amortization expense;
--  gain (loss) on sale of assets;
--  provision for impairment of gas and oil properties;
--  cumulative effect of accounting change, net of tax;
--  change in derivative fair value; and
--  non-cash compensation expense.

Adjusted EBITDA is a significant performance metric used by the Partnership's management, and by external users of its financial statements, such as investors, commercial banks, research analysts and others, to assess (prior to the establishment of any cash reserves by the Partnership's general partner) the cash distributions the Partnership expects to pay its unitholders. Specifically, this financial measure indicates whether or not the Partnership is generating cash flow at a level that can sustain or support an increase in its quarterly distribution rates without regard to the impact of financing methods, capital structure or historical cost basis of its assets.

Adjusted EBITDA is also used as a supplemental liquidity measure by the Partnership's management, and by external users of its financial statements, such as investors, commercial banks, research analysts and others, to assess the ability of the Partnership's assets to generate cash sufficient to pay interest costs, support its indebtedness, and make distributions to its unitholders.

The Partnership's revolving credit agreement requires the Partnership to maintain a minimum ratio of consolidated EBITDA plus distribution equivalents paid on unvested equity incentive compensation awards, if any, to consolidated interest expense (as defined in its credit facility) and a maximum ratio of total debt (as defined in its credit facility) to consolidated EBITDA plus distribution equivalents paid on unvested equity incentive compensation awards, if any. Consolidated EBITDA under the Partnership's revolving credit agreement is computed in the same manner as the way Adjusted EBITDA is presented in this press release. the Partnership's management believes it is important to maintain consistency between the way the Partnership reports Adjusted EBITDA and the way the Partnership is required to calculate consolidated EBITDA for purposes of its revolving credit agreement.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. Adjusted EBITDA does not include interest expense, income taxes, depreciation and amortization expense, change in derivative fair value or non-cash compensation expense. Because the Partnership's predecessor has borrowed, and the Partnership intends to borrow, money to finance the Partnership's operations, interest expense is a necessary element of the Partnership's costs. Because the Partnership uses capital assets, depreciation and amortization are also necessary elements of its costs. Because the Partnership's predecessor has used, and the Partnership intends to use, derivative contracts to hedge its exposure to commodity prices, changes in the fair value of those contracts is also a necessary element of its costs. Because the Partnership's predecessor has used, and the Partnership intends to use, non-cash equity awards as part of its overall compensation package for directors, non-cash compensation expense is a necessary element of its costs. Due to fluctuations in commodity prices, Impairments of oil and gas properties may at times be a material element of the Partnership's business. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, the Partnership's management believes that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate the Partnership's financial performance and its liquidity.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into management's decision-making processes.

  Reconciliation of Net Income (Loss) to Adjusted EBITDA (in $thousands)

                                             Inception (November 15, 2007)
                                                 through December 31, 2007
Net income (loss)                                                  (18,511)
Net interest expense                                                13,746
Change in derivative fair value                                      6,082
Depreciation, depletion, and amortization                            5,046
Sale of assets                                                          18
Adjusted EBITDA                                                      6,381

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA
 (in $thousands)
                                             Inception (November 15, 2007)
                                                 through December 31, 2007
Net cash from operating activities                                (263,684)
Net interest expense                                                13,746
Other depreciation, depletion, and amortization                       (383)
Other change in derivative fair value                               (1,152)
Non-cash, stock compensation                                             0
Change in current assets and liabilities                           257,854
Other net cash changes                                                   0
Adjusted EBITDA                                                      6,381

Contact Information

  • Company Contact:
    Jack Collins
    Investor Relations
    Phone: (405) 702-7460