Chaparral Energy (CHAP) 8-K Chaparral Energy 3rd Quarter Conference Call

Exhibit 99.1

Chaparral Energy 3^rd Quarter Conference Call

Operator:	Good morning, ladies and gentlemen, and welcome to the Chaparral Energy third quarter 2006 conference call. At this time, all participants are in a listen-only mode. Following today’s presentation, instructions will be given for the question-and-answer session. If anyone needs assistance at any time during the conference, please press the star followed by the zero. I would now like to turn the conference over to Jack Lascar of DRG&E. Go ahead please.
Jack:	Thank you, Operator, and good morning everyone. We appreciate you joining us this morning for Chaparral Energy’s conference call to review third quarter 2006 results. And before I turn the call over to management, I have a few items to go over.
	If you would like to be on the company’s email distribution list to receive future news releases, please call our offices at DRG&E, and we’ll be glad to put you on our bondholder email list. That number is 713-529-6600.
	Please note that information on this call speaks only of events as of today, November 16, 2006.
	Also, today management is going to discuss certain topics that contain forward-looking information, which is based on management’s beliefs as well as assumptions made by and information currently available to management. Forward-looking information includes statements regarding information or assumptions about capital and other expenditures, financing plans, capital structure, cash flows, pending legal and regulatory matters, future performance, cost savings and management’s plans, strategies, goals and objectives for future operations and growth. Although management believes that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks, uncertainties and assumptions, including among other things market conditions, oil and gas price volatility, uncertainties

	inherent in oil and gas production operation, estimating reserves, unexpected future capital expenditures, competition, the success of risk management activities, governmental regulations and other factors described in the 10-Q filed with the Securities and Exchange Commission on November 14, 2006.
	Should one or more of these risks materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those expected. Please also note that this conference call contains references to non-GAAP financial measures. You can find reconciliations of these non-GAAP financial measures to GAAP financial measures in an 8-K to be filed by the Company after this call.
	Now I would like to turn the call over to Mark Fischer, CEO and President of Chaparral Energy.
Mark Fischer:	Thanks, Jack, and good morning everyone. The purpose of the call today is to discuss our third quarter 2006 results and provide an update of our business operations and activities. My name is Mark Fischer and I’m CEO and President of Chaparral Energy. Here with me today is Joe Evans, our Chief Financial Officer. Also with us, to assist in the Q & A session is Chuck Fischer, our Chief Administrative Officer, Larry Gateley, our Sr. VP of Reservoir Engineering, Jim Miller, our Sr. VP of Production Engineering and Operations, and Bob Kelly, our Sr. VP of Land and Legal and General Counsel.
	Today’s agenda will be in three sections. First, I will give you some brief highlights of our third quarter and an update of our operations since our last call, then I will turn the call over to Joe, who will provide a more detailed review of third quarter financial information and lastly I will then finish up with a few additional highlights before taking your questions.
	Essentially, we had a good third quarter, both operationally and financially. The quarter was highlighted by two major events. The first was an equity transaction whereby Chesapeake Energy Corporation purchased 280,000 shares of our common stock, of which 102,000 shares were primary shares, bringing in equity to the company of $102 million. This transaction closed on September 29th. With this transaction, Chesapeake currently has a 32% equity stake in Chaparral. The second event was the entering into a Securities Purchase Agreement on September 16

whereby Chaparral agreed to acquire all of the outstanding common stock of Calumet Oil Company, all of the limited partnership interests of JMG Oil and Gas, L.P. and all of the membership interests in the General Partner, J.M. Graves L.L.C. for an aggregate purchase price of $500 million. We closed this transaction after the end of the third quarter on October 31. Chaparral financed the transaction through its newly arranged $750 million four year senior secured credit facility with a bank group led by JP Morgan Chase Bank and from the $102 million in proceeds from Chaparral’s private placement of its common stock to Chesapeake. Reemphasizing some statements in earlier announcements, this acquisition was an excellent fit for Chaparral both geographically and operationally, and came to us at what we believe was a very attractive price. We had originally projected estimated proved reserves of 309 Bcfe and the final third party engineering report has increased these estimated proved reserves as of September 30, 2006 to 410 Bcfe. Calumet’s two prize properties, the North Burbank Unit and the Fox Deese Springer Unit will allow Chaparral to take its enhanced oil recovery program and drilling program to the next level. Calumet’s average daily production is 28 mmcfe, which should boost Chaparral’s daily production to a projected 115 mmcfe. It is probably also important to note that the Calumet acquisition was 93% oil. To lock in much of the benefit of this transaction and to support our financing agreement, we have hedged 80% of our combined estimated production from proved developed producing oil reserves for five years at prices ranging from $63 to $68 per barrel. Many of the other details surrounding these transactions can be found in our various announcements but I think it is important to say that these transactions were large enough in magnitude to make a significant impact on Chaparral overall and will help to achieve the size and scale that we would like to have in moving towards the public market.

Now continuing on, as you know, the commodity markets continue to be quite volatile. Crude prices moved lower through the quarter, while natural gas prices moved upward gradually before dramatically falling near the end of the quarter. Fortunately, our gas hedges helped mitigate this volatility. Our third quarter, although significantly improved over our third quarter last year, was still slightly below our expectations. A quick overview of our third quarter results follows. In considering these, please keep in mind that our 2006 performance figures

include the contribution from the CEI Bristol Acquisition Properties, which we acquired on September 30, 2005.

•      Our oil & gas sales revenue for the quarter before hedging activities rose by 14% from a year ago to $60 million.

•      Net income rose to $6.8 million, up 163% from a year ago

•      Our Adjusted EBITDA was $30.4 million, up 41% from a year ago.

•      Our production for the quarter totaled 7.6 BCFE, which is up approximately 23% from a year ago. However, our 3^rd quarter production is down approximately 6% from the second quarter 2006. The decline from the second quarter production was a result of two main factors. The first being the one-time recognition of .4 Bcfe of production for prior periods from a disputed ownership interest that was favorably settled in the second quarter. Secondly, we experienced a delay in bringing on the Haley #36-4 to maximum capacity and the casing failure that we had on the Haley #38-2 well. Currently, the 36-4 well is now producing at rates in excess of 8 mmcfepd. On the Haley #38-2 well, we have decided to temporarily abandon the zones below the casing failure and move uphole to the Atoka lime and Bone Springs intervals, both of which could have significant production.

Turning to operations, we continue to achieve a high level of success with our drilling program. During the quarter, we drilled 22 operated and 29 outside operated wells for a total of 51 wells and had a 100% success rate. These wells were located in areas generally consistent with our budgeted drilling capital expenditures with 37 wells or 73% of the total wells drilled in our core areas of the Mid-Continent and Permian Basin.

We slowed down our drilling program from 7-8 operated drilling rigs running in the second quarter to an average of 4-5 rigs running in the third quarter. This was done in response to reduced commodity pricing and because of higher drilling costs. We expect to maintain this reduced drilling rate by keeping three rigs drilling for the remainder of this year.

Overall, through September 30, 2006, we have spent $157 million on capital expenditures for oil & gas properties. Based on this reduced drilling activity, we currently anticipate being below our projected annual capital expenditures of $210 million.

Moving on to our completion and workover activities, we have 29 completion and workover rigs currently running and have seen promising results on a number of these wells.

From a well enhancement and workover standpoint, we spent $7.8 million compared to our budget of $5.6 million. This increased expenditure was a result of a higher number of workovers being performed as well as higher well servicing costs.

During the quarter, we continued processing the 3D seismic data over our Harmon County, Oklahoma Play where we have approximately 29,000 acres under lease. Results look promising on a number of structural features within the seismic area. We are moving in a drilling rig next week to initiate drilling operations on 4 wells in this prospect. We shot 18.6 square miles of 3D seismic data on our Sterling County, Texas prospect and are currently processing it with initial indications looking very positive. We are continuing to acquire and process additional 3D seismic in other areas and are working a number of nice prospects on those shoots.

On the acquisition front, as a result of an industry wide slow down on divestures, we were below our budgeted expenditure level. Acquisitions for the quarter totaled $4.9 million, which was below our budgeted figure of $20 million.

On the CO2 front, we have completed our Borger CO2 plant expansion and brought it on line in September which increased our CO2 volume by 11 Mmcf/d to a total of 18 Mmcf/d. We acquired 123 miles of pipeline in the Oklahoma Panhandle area which will assist us in the acquisition and distribution of CO2. We are also pursuing a number of interesting leads regarding the acquisition of CO2 volumes that should allow us to move forward our enhanced oil recovery program at an increasing pace. Lastly, I should probably give you an update on our ethanol plant in Enid, Oklahoma. We have finalized contracts with ADM for grain storage and throughput processing, we have finalized the TIF District Agreement with the City of Enid and we have entered

	into a Limited Notice to Proceed Agreement with BRG for design and construction of the plant. We are currently working to finalize the EPC contract with BRG. Significant issues with regard to equipment pricing and availability have developed due to the extremely busy construction environment that currently exists. This will probably delay the start of construction of the plant until at least the second quarter of next year. Current ethanol pricing has fallen from its peak which might help reduce some of the construction delays and increased costs that we have seen recently.
	Ok with that summary, I would now like to hand the call over to Joe Evans, our CFO. …Joe?
Joe Evans:	Thanks, Mark. I would also like to thank all of you for joining us today.
	Please note on November 14, 2006 we filed a 10-Q and the financial information we discuss today is shown in that filing which is publicly available on the EDGAR system from the SEC.
	Turning to our third quarter 2006 financials, we had net income of $6.8 million, compared to $ 2.6 million for the same period last year.
	The improvement in earnings was primarily the result of higher production volumes, increased oil prices and a gain from our hedging activities. This was partially offset by reduced gas prices, higher lease operating, DD&A and interest expense.
	EBITDA for the third quarter came in at $30.4 million, up from $21.4 million last year. The same factors that led to the improvement in our net income were also the drivers behind the increase in our EBITDA.
	For the latest quarter, oil and gas sales before the impact of hedging activities were $ 60 million, an increase of 14% over the third quarter of 2005. Hedging activities increased our revenues by $1.3 million, compared to hedging losses of $22.3 million recorded a year ago. The net effect of our hedging program increased our average realized prices by $.17 per Mcfe in the third quarter of 2006, compared to a decrease of $3.60 per Mcfe for the same period last year. For the third quarter of 2006 our average realized oil price per barrel after hedging was 76% of the price before hedging compared to 66% for the third quarter of 2005. For 2006 we realized $50.41 per barrel after hedges

compared to $66.19 per barrel before hedging and for 2005 we realized $39.62 per barrel after hedges compared to $59.97 per barrel before hedging. For gas, our third quarter 2006 average realized price per mcf after hedging was 124% of the price before hedging compared to 51% for the third quarter of 2005. For 2006 we realized $7.81 per Mcf after hedges compared to $6.28 per Mcf before hedging and for 2005 we realized $3.85 per Mcf after hedges compared to $7.56 per Mcf before hedging.

Lease operating expenses rose by $ 5.8 million over last year, primarily due to an increase in the number of net producing wells, in large part from the CEI Bristol purchase, and higher oilfield service costs. We also incurred $2.2 million of costs associated with workovers during the third quarter of 2006 compared to $1.0 million in the same period last year. On a per unit basis, our lease operating expense per Mcfe was $2.07, compared to $ 1.59 per Mcfe for the same period a year ago.

Production taxes, which include ad valorem taxes were $4.3 million, or $ 0.57 per Mcfe, down slightly from $0.59 per Mcfe a year ago.

DD&A was $12.0 million, which was a 64% increase over 2005. On a per unit basis, DD&A for oil and gas properties averaged $1.41 per Mcfe, up from $1.01 a year ago. This increase primarily reflects higher estimated future development costs for proved undeveloped reserves.

G&A expense increased by $.5 million compared to the third quarter of 2005, and averaged $0.40 per Mcfe, for both periods. The $500,000 increase is related to staffing and additional costs caused by our increased level of activity.

Interest expense was $10.3 million, up from $3.2 million in the third quarter of 2005, primarily reflecting the additional interest related to the 8.5% Senior Notes.

During the third quarter of 2006 we incurred $4.5 million of unrealized losses on derivative contracts that did not qualify for hedge accounting. This includes $1.8 million on natural gas basis differential contracts and $2.7 million on other derivative contracts entered into in preparation for the Calumet acquisition Mark referred to earlier.

Moving on to our balance sheet, as of September 30, 2006, we had total debt outstanding of $540 million, which consists of the $325 million senior notes and approximately $215 million of bank debt and other debt obligations.

On September 29^th we completed the previously announced sale of common stock to Chesapeake resulting in net proceeds of approximately $101 million. This helped increase our total stockholders’ equity to $173 million, compared to $45 million at the end of the second quarter 2006.

It should be noted that our third quarter ending balance sheet does not reflect the funding of the Calumet acquisition, but does include the proceeds from the private equity sale. Factoring in Calumet and the associated debt financing, which both closed at the end of October, our pro-forma balance sheet would have approximately $968 million of total debt, and stockholders’ equity would remain unchanged at $173 million.

In conjunction with the Calumet transaction, we entered into a new bank credit facility on October 31, 2006, which provides us with a $750 million maximum commitment amount. As of October 31^st, we had $629 million outstanding under our Credit Agreement. We currently have approximately $121 million of availability under this credit facility.

Turning to our hedging position, as of September 30, 2006, we had hedges in place for approximately 66%, 58% and 18% of our estimated PDP gas production for 2006, 2007 and 2008, respectively, with average quarterly hedged prices ranging from $7.04 to $10.07 per MMbtu. We also had hedges in place for approximately 73% to 94% of our estimated quarterly PDP oil production through the fourth quarter 2011, with average quarterly hedged prices ranging from $ 48.63 to $68.30 per barrel.

Under the terms of our new Credit Agreement that was entered into as part of the Calumet acquisition, we were required to have five year hedges in place for 80% of the combined Chaparral and Calumet oil production. As part of the acquisition, we assumed the existing swaps that Calumet had in place and we also entered into additional crude oil swaps and swaption contracts as of September 30, 2006.

	The cost of the swaption was $2.8 million. The swaption contracts and the additional swaps we entered into do not qualify as hedges under FAS 133 and therefore the changes in fair value of these contracts are recognized in non-operating income as non hedge derivative losses. At September 30 we had swaps for 60,000 barrels in 2009 and 2010 and 180,000 barrels in 2011 at an average price of $63.63 which did not qualify as hedges. During October we entered into additional swaps for 1,076,000 barrels for a total average price on non-hedge swaps of $65.71.
	This concludes my remarks and I will now hand the call back to Mark.
Mark Fischer:	Thanks, Joe. Now let’s move on and let me talk some about what we have going on right now and about our plans for the remainder of 2006 and beyond.
	We are currently running 3 rigs and probably will continue to maintain this lower level throughout the remainder of the year. Elaborating somewhat on the drilling program, our expectations are: to keep one rig running in the Western Oklahoma area drilling Redfork and Cleveland sands; to commence drilling operations with one rig in our Harmon County 3D shoot area; and to initiate a one rig program in the Calumet acquired Fox Deese Springer Unit in southern Oklahoma to prove up increased density drilling from 10 acres to 5 acres.
	We have just completed a 3-well drilling program in our Dover Unit in Oklahoma to determine the feasibility of downspacing from 80 acres to 40 acres in the Manning and Oswego intervals and to determine the feasibility of CO2 flooding. These wells are in the completion process and results will dictate future drilling opportunities in this field
	•     From a 3D seismic standpoint, we are moving forward with our 51 square mile 3D shoot in the Mustang Island Area and a 26 Square mile 3D shoot in Mesquite Bay. The expected start date for the Mustang Island shoot will be in November of this year.
	•     On the acquisition front and as mentioned earlier, we closed the $500 million Calumet acquisition in October. Efforts are currently underway to integrate this large acquisition into our

company with overall good success being reported by all departments. Smaller acquisitions have been slow but may pick up during the last quarter of the year, which would be consistent with historical trends.

•     Our CO2 program is also moving forward with additional expansions planned at our Camrick Unit. As mentioned earlier, we completed the installation of additional compression at our Borger, Texas facility. This allowed us to initiate phase two of our program at Camrick which includes converting additional wells to injection and returning additional wells to production. Our latest 3 well drilling program has been successfully completed in our Camrick CO2 flood. Gross production is in excess of 900 BOPD. From an overall CO2 standpoint, we are focusing our efforts on acquiring additional CO2 supply to move our overall program forward.

•     One facet of our CO2 acquisition program is the installation of an ethanol plant in Enid, Oklahoma, which I mentioned earlier, and which should generate approximately 7 MMCFGPD of CO2. As a brief overview, our JV with Oklahoma Farmers Union is moving forward. They completed their offering and raised approximately $7.5 million of an expected $12.5 million. By agreement, the remaining portion will be contributed by a private third party. Start up and construction costs were originally estimated to be approximately $90 to $95 million. However, we anticipate these costs to move upward because of the high demand ethanol environment. Various financing options are currently being reviewed.

That concludes our prepared remarks and we would now like to open the call up for questions.

Q&A

After Q&A, Mark says:

We appreciate you joining us today and look forward to talking with you again soon.

Adjusted EBITDA

We define Adjusted EBITDA as income before accounting changes, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization and (4) hedge ineffectiveness and derivative mark-to market adjustments.

Our Adjusted EBITDA measure provides additional information which may be used to better understand our operations. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under generally accepted accounting principles and, accordingly, it may not be a comparable measurement to those used by other companies. The following table provides a reconciliation of income before accounting changes to Adjusted EBITDA.

	3 months ending September 30,					9 months ending September 30,
(Dollars in thousands) (unaudited)	2005		2006			2005		2006
Net income	$	2,595	$	6,812		$	11,503	$	23,317
Interest expense		3,235		10,335			8,283		28,993
Income tax expense		1,013		4,241			6,672		14,520
Depreciation, depletion and amortization		7,277		11,967			20,579		35,163
Unrealized (gain) loss on ineffective portion of hedges		7,233		(7,511	)		11,680		(17,566	)
Unrealized loss on change in fair value of derivative instruments		—		4,522			—		4,634
Adjusted EBITDA	$	21,353	$	30,366		$	58,717	$	89,061